27.7
                                  DIFF, SNCR
                              VI WAPA Turbine 12
                                      12
                                   St Thomas
                                     15.0
                                     15.0
                                     99.0
                                      0.2
                                     14.9
                                   DIFF, SCR
                              VI WAPA Turbine 14
                                      14
                                   St Thomas
                                     16.0
                                     16.0
                                     99.0
                                      0.2
                                     15.8
                                   DIFF, SCR
                               VI WAPA Boiler 10
                                      10
                                   St Croix
                                     45.0
                                     45.0
                                     99.0
                                      0.5
                                     44.6
                                  DIFF, SNCR
                               VI WAPA Boiler 11
                                      11
                                   St Croix
                                     81.0
                                     81.0
                                     99.0
                                      0.8
                                     80.2
                                  DIFF, SNCR

Steam Boilers
HOVENSA owns and operates nine steam boilers that are capable of combusting either refinery fuel gas (RFG) or No. 6 fuel oil and the heat input to the boilers is in the range of 205 to 405 mm BTU/hr.
One of the boilers (Boiler 10) was constructed in 1999 and therefore is not BART-eligible.  EPA has determined that the following boilers are subject to BART: Boilers 1 (B-1151), 3 (B-1153), 4 (B-1154), 5 (B-1155), 6 (B-3301), 7 (B-3302), 8 (B-3303, and 9 (B-3304).  HOVENSA has indicated that Boiler 2 is no longer in service.  SO2 emissions are controlled by a permit limiting the sulfur content of No. 6 fuel oil to 0.50% or 1.0% depending upon wind conditions.  In addition, the June 2011 consent decree will lower SO2 emissions by requiring that the combustion of RFG, containing hydrogen sulfide (H2S), meet the requirements of the New Source Performance Standards (NSPS) at Part 60, subparts J and Ja: Boilers 1-5 subject to BART must meet subpart Ja requirements that limits the H2S content of RFG to 162 ppmv (3-hour rolling average) and 60 ppmv (daily on a 365 day rolling average); Boilers 6-9 subject to BART must meet the subpart J requirements that limits the H2S content of RFG to 0.10 grains per dry standard cubic feet (equivalent to about 162 ppmv).  The June 2011 consent decree will also lower the sulfur content of No. 6 fuel oil to 0.55% maximum , 0.50% annually, and to a low limit 0.30% should wind conditions warrant this (as defined in the CD).  There are no existing controls for NOx and PM emissions from the BART-eligible boilers.
For control of SO2, NOx and PM emissions, based upon EPA's analysis, EPA is proposing that current operations represent BART for each of the boilers subject to BART.  For SO2 and PM control, EPA's contractor evaluated Duct Injection and Fabric Filters (DIFF) using lime as the alkaline reagent.  DIFF is a semi-wet flue gas desulfurization (FGD) process, with additional water added to humidify and cool the gas stream to the desired reaction temperature.  The fabric filter is the PM control device that would collect the sulfur reactant products and any PM formed directly from the combustion process.  EPA determined that the cost effectiveness for the eight boilers subject to BART varied in the range of about $19,100 to $39,600 per ton of SO2 and PM reduced.  EPA has determined that for the DIFF controls evaluated for the boilers subject to BART, Boilers 1 and 3-9, the cost-effective values are too high to be effective control.   In addition, it is EPA's opinion that if maximum controls had been evaluated, such as lime or limestone wet FGD, the cost effectiveness would be even higher than for the DIFF controls evaluated.  Therefore, EPA determines that for SO2 and PM controls, current operation is considered as BART.
	For control of NOx emissions, EPA's contractor evaluated selective non-catalytic reduction (SNCR) using ammonia as the reagent.  EPA has determined that implementation of SNCR controls for boilers subject to BART are cost effective.  The actual cost effectiveness for the boilers is in the range of about $710 to $860 per ton of NOx removed.  As summarized in Table 8, the visibility impact (98[th] percentile, 4 year average, see modeling report in the Appendix) of all BART-eligible sources at HOVENSA on two receptors in the Class I area, St. John and Hassel Island near St. Thomas are 1.91 dv and 2.35 dv, respectively for all pollutants.  EPA further analyzed the contribution of various chemical species and components on the visibility impacts and has established that the contribution of NOx compounds from all potential BART sources at HOVENSA is about 5% which would be equivalent to about a 0.09 dv visibility impact at St. John and 0.91 for Hassel Island from all HOVENSA units subject to BART.  EPA has not analyzed the portion of the NOx contribution specifically from only the 8 boilers subject to BART since HOVENSA is not currently operating the refinery process units.  Since HOVENSA is not currently operating as a refinery, EPA proposes to determine that HOVENSA is not subject to implementing any new NOx controls at this time and therefore EPA proposes to determine that current operation of the boilers subject to BART is considered BART for controlling NOx emissions.  Regardless, as discussed in the RPG section, EPA is proposing to require HOVENSA to do a new reasonable measure analysis (if they resume operations) for those units that will be in operation.
Combustion Turbines
HOVENSA owns and operates eleven combustion turbines that are capable of combusting two or more of the following fuel combinations: refinery fuel gas (RFG), liquefied petroleum gas (LPG) and distillate oil.  Two of the turbines (GT 10 and GT 13) were constructed in 1993 and 2009 and are therefore not BART-eligible.  EPA has determined that the following nine turbines are subject to BART: GT1 (G-1101E), GT2 (G-1101F), GT3 (G-1101G), GT4 (G-3404), GT5 (G-3405), GT6 (G-3406), GT7 (G-3407), GT8 (G-3408), and GT9 (G-3409).  These turbines generate electricity for use at the facility, each in the range of 17.5  -  24 MW for a total nominal generating capacity of about 169 MW.  SO2 emissions are controlled by limiting the fuel sulfur content as follows: distillate oil has a permit sulfur limit of 0.20%; LPG does not contain any sulfur; RFG sulfur content will be limited by the CD that requires the combustion of RFG with limits on the H2S content in accordance with the NSPS requirements at subpart J or Ja; turbines GT Nos. 1, 2 and 3 must meet subpart Ja requirements limiting the H2S content of the RFG to 162 ppmv (3-hour rolling average) and 60 ppmv (daily on a 365 day rolling average); turbines GT Nos. 4 through 9 must meet subpart J requirements limiting the H2S content of the RFG to 0.10 grains per dry standard cubic feet (equivalent to 162 ppmv).  HOVENSA has indicated to EPA that turbines GT1 through GT3 typically combusts LPG; turbines GT4 through GT 8  typically combusts RFG that is already compliant with Subpart J limits for H2S; and for GT9, the permit limits this turbine's gaseous fuels to propane and butane. For NOx, only turbine GT9 has implemented control technology (steam injection).  For PM, none of the turbines subject to BART have any controls.
For control of SO2, NOx and PM emissions, based upon EPA's analysis, EPA is proposing that current operations represent BART for each of the nine combustion turbines subject to BART.  For SO2 and PM control, as with the boilers discussed above, EPA's contractor evaluated Duct Injection and Fabric Filters (DIFF) using lime as the alkaline reagent.  Based upon this analysis, EPA has determined that the DIFF controls evaluated for the nine combustion turbines subject to BART are not cost effective because it exceeds a reasonable cost effectiveness for this kind of source.  EPA determined that the cost effectiveness for the nine combustion turbines subject to BART varied in the range of about $122,300 (8 turbines) to $359,186 (1 turbine) per ton of SO2 and PM reduced.  The cost effectiveness values for the combustion turbines are much higher than for the boilers because the SO2 emissions from the boilers are much higher (by a factor of 2 to 4 times) than from the turbines.  Therefore, EPA determines that for SO2 and PM controls, current operation is considered as BART.
For control of NOx emissions, as discussed above for the boilers, EPA's contractor evaluated selective non-catalytic reduction (SNCR) using ammonia as the reagent.  EPA has determined, except for turbine GT9, that implementation of SNCR controls for eight turbines subject to BART, GT1 through GT8, the cost in dollars per ton is low enough to be cost-effective. The actual cost effectiveness for the turbines GT1 through GT 8 is in the range of about $1750 to $1890 per ton of NOx removed.  The actual cost effectiveness for turbine GT9 is about $9,500/ton and is too high to be cost effective.  The cost effectiveness of turbine GT9 is much higher than the other eight turbines because the NOx emissions are much lower due to NOx controls installed on GT9.
Even though eight of the nine turbines subject to BART have cost effective values within acceptable limits of EPA's cost benchmark, EPA has determined, for the same reasons discussed above for the boilers, that the visibility impact due to NOx emissions is only about 0.09 dv from all HOVENSA units subject to BART, and therefore the implementation of any new NOx controls (even SNCR or SCR) on the combustion turbines would not have enough of a improvement in visibility on the Class I area in the Virgin Islands.  Therefore, EPA is determining that current operations of the nine turbines subject to BART are considered BART for controlling NOx emissions.
Process Heaters
HOVENSA owns seventy process heaters of which twenty-one were shut down in early 2011.  Of the seventy heaters, EPA has determined that sixty-four are subject to BART whereas the remaining six heaters were constructed after 1977 and are therefore not BART-eligible.  Of the sixty-four process heaters subject to BART, fifteen are capable of combusting either RFG or No. 6 fuel oil whereas the remaining forty-nine heaters combust only RFG.  EPA has determined that the following list of sixty-four process heaters are subject to BART:  H-101, H-104, H-200, H-201, H-202, H-401 A-C, H-1401 A and B, H-1500, H 1501, H-160, H-600 through H-606, H-800A and B, H-801, H-2101, H-2102, H-2201A and B, H-2202, H-2400, H-2401, H-2501, H-4502 through H-4505, H-3101A and B, H-4101A and B, H-4401, H-4402, H-4451 through H-4455, H-4201, H-4202, H-5401, H-5402, H-5451 through H-5455, H-4601A and B, H-4602, H-4301A and B, H-4302, H-5301A and B, and H-5302.
For the fifteen heaters capable of combusting No. 6 fuel oil, SO2 emissions are controlled by permit limiting the sulfur content of No. 6 fuel oil to 0.50% or 1.0% depending upon wind conditions.  The June 2011 CD may lower SO2 emissions by establishing the sulfur content of No. 6 fuel oil to 0.55% maximum, 0.50% annually, and to a low limit 0.30% should wind conditions warrant this (as defined in the CD).  In addition, the CD requires process heaters to limit the H2S content of RFG in accordance with the NSPS at Part 60, at either subpart J (about 162 ppmv H2S) or Ja (162 ppmv H2S on a 3 hour rolling average and 60 ppmv H2S daily on a 365 day rolling average).  Appendix A of the CD identifies which process heaters are subject to either subparts J or Ja.  None of the process heaters subject to BART have any controls for either NOx or PM.
For control of SO2, NOx and PM emissions, based upon EPA's analysis, EPA is proposing that current operations represent BART for each of the sixty-four process heaters subject to BART.  Although EPA's contractor determined cost effectiveness for only the boilers and combustion turbines, EPA has concluded that, for control of SO2, NOx and PM, there is sufficient information to make a determination that current operation represents BART for each of the process heaters subject to BART.  For the SO2 and PM BART determination, EPA notes that the SO2 emissions, heat input and fuel type for the each of the six largest process heaters is similar to that of most of the boilers which EPA's contractor established cost effectiveness values that EPA believes are too high to be cost effective.  It is EPA's judgment from this size comparison between the boilers and the six largest heaters that the cost effectiveness for the process heaters would be less than for the boilers but still excessive.  The great majority of the remainder of the process heaters combust only RFG, have a smaller heat input (each by a factor of about 2.75 average) and have lower SO2 emissions (each by a factor of about 7.8 on average) than the six large heaters.  Based upon this comparison, EPA would expect that the remaining smaller process heaters will also have a cost effectiveness that are sufficiently excessive to make these potential controls not cost effective.  Therefore, for SO2 and PM control, EPA proposes to determine that the process heaters subject to BART are all not cost effective for controlling SO2 and PM emissions and that current operation is considered BART.
As discussed above for the boilers and combustion turbines, EPA determined that implementation of controls on NOx emissions from all BART units at HOVENSA have an insignificant visibility impact on the Class I areas in the Virgin Islands and therefore EPA is proposing to determine this is also true for the process heaters.  Therefore EPA proposes that current operation of the process heaters subject to BART is considered as BART for controlling NOx emissions.
Reciprocating gas compressors
HOVENSA owns eleven compressors of which five were shut down in early 2011.  EPA has determined that the following eleven compressors are subject to BART:  C-200A through C, C-1500 A through C, C-2400 A and B, and C-4601 A through C.  Five of the compressors (C-200 A through C and C-2400 A and B) are equipped with catalytic converters (similar to those used on cars) for controlling NOx emissions.  These eleven compressors combust only liquefied petroleum gas (LPG) and therefore there are no emissions of SO2 and PM emissions are small, as indicated by emissions data from HOVENSA.
For control of SO2, NOx and PM emissions, based upon EPA's analysis EPA is proposing that current operations represent BART for each of the eleven reciprocating gas compressors subject to BART.  Since there are no SO2 emissions and PM emissions are small, EPA is proposing that current operation using LPG fuel represents BART for control of SO2 and PM emissions from the eleven reciprocating gas compressors subject to BART.  NOx reductions will not have a useful impact on improving visibility.
Tail Gas Treatment Units
HOVENSA owns and operates two Tail Gas Treatment (TGT) units and components of each unit combust RFG.  EPA has determined that one of the TGT units, No. 2 Beavon (which includes H-4761(Reduced Gas Generator) and T-4761 (Stack)), is subject to BART whereas the other unit, No. 1 Beavon (which includes H-1061 (Reduced Gas Generator) and T-1061 (Stack)) was constructed after 1977 and is therefore not BART-eligible.  The TGT units ("Beavons") are control devices for the sulfur recovery plants and the two TGT units process tail gas from the four sulfur recovery units (SRU) in order to lower emissions of sulfur compounds and to recover additional sulfur.  The TGT unit subject to BART (No. 2 Beavon including H-4761 and T-4761) processes tail gas from No. 3 SRU and No. 4 SRU and emissions of SO2, NOx and PM are low (potential to emit (PTE): 2 tpy SO2 and 4.0 tpy NOx) as compared to other units at this refinery facility (e.g., Boiler No. 1 PTE: 330 tpy SO2 and 450 tpy NOx).  Since the emissions are so low for the TGT unit subject to BART, it is EPA's judgment that any BART analysis for additional controls would have resulted in cost effectiveness values too to be cost effective for BART.  Furthermore, as discussed above for other units subject to BART, any reduction of NOx emissions would not have any significant impact on visibility and therefore current operations represents BART for control of NOx emissions.  Also, it should be noted that the CD requires that (1) by the end of 2014, HOVENSA install a second TGT unit to service the No. 3 and No. 4 SRUs; and (2) by April 1, 2015, the H-4761 section of the TGT unit must be in compliance with the NSPS Part 60, subpart Ja concerning the H2S concentration limit of the RFG.
Therefore, based upon the above analysis, EPA is proposing that current operations without any new controls represent BART for the TGT unit subject to BART.
Tail Gas Incinerators
HOVENSA owns and operates three Tail Gas Incinerators (TGI) and each combusts RFG.  EPA has determined that all three of the TGI units (H-4745, H-1032 and H-1042) are subject to BART.  The TGI units are part of the sulfur recovery plants that include the Tail Gas Treatment (TGT) units described above as well as for flare units as well as other units that are not needed for consideration for this BART determination.  It is EPA's understanding that: (1) two incinerators (H-1032 and H-1042) are associated with No.1 and 2 SRUs and these TGIs are used during startup, shutdown and malfunction of those SRUs or during a malfunction of the associated TGT unit (No. 1 Beavon which includes H-1061 and T-1061); and (2) one incinerator (H-4745) is associated with No. 3 and 4 SRUs and is used during periods of maintenance or malfunction of  the associated TGT unit (No. 2 Beavon which includes H-4761 and T-4761) as well as during startup,  shutdown or malfunction of these SRU units.
TGI unit H-4745 has much higher annual emissions (PTE: 900 tpy SO2 and 28 tpy NOx; actual emissions: 228 tpy SO2 and 7.0 tpy NOx) than each of the other two incinerators.   However, as discussed above for the TGT unit, the CD requires that, by the end of 2014, HOVENSA is to install a second TGT unit to service the No. 3 and No. 4 SRUs.  Under this scenario there would be two TGT units (No. 2 Beavon which includes H-4761 (Reduced Gas Generator) and T-4761 (Stack) and a new TGT unit) servicing No. 3 and 4 SRUs, and because of this redundancy in TGT units, the use of incinerator H-4745 might only be used for startup, shutdown and malfunction of the associated TGT unit (either the No. 2 Beavon system or the new TGT unit).   Under this redundancy situation, HOVENSA expects that the PTE for SO2 for incinerator H-4745 would be reduced from 900 tpy to a small fraction of this current PTE and, in addition, SO2 emissions would meet the NSPS emission limits under Part 60 subparts J or Ja.
Since TGI units H-1032 and H-1042 have very low air pollutant emissions and TGI unit H-4745 would also have low air pollutant emissions once in compliance with the CD, it is EPA's judgment that any BART analysis for additional controls would have resulted in high cost effectiveness values.   Furthermore, as discussed above for other units (boilers, turbines etc) subject to BART, any reduction of NOx emissions would not have any significant impact on visibility and therefore EPA proposes that current operation represents BART for control of NOx emissions.  Also, it should be noted that the CD requires that each of the three TGI units subject to BART must be in compliance with the NSPS Part 60, subpart Ja such that the emissions of SO2 are limited to not more than 250 ppmv (at zero percent excess air)  -  TGI unit H-4745 must comply by April 1, 2015 and TGI units H-1032 and H-1042 must comply by December 31, 2011.
Therefore, EPA is proposing that current operations without any new controls of SO2, NOx and PM emissions represent BART for the three TGI units subject to BART.

Flares
HOVENSA owns and operates eight flares throughout the refinery.  HOVENSA indicates that the flares are used primarily as safety devices for purposes of relieving accidental over-pressuring.   EPA has determined that five of the flares (No 2 (H-1105), No. 3 (H-1104), No. 5 (H-3351), No. 6 (H-3352), No. 7 (H-3301)), all located within the sulfur recovery plant, are subject to BART.  Flares 1 and 4 are no longer in service.  Each flare subject to BART includes a steam injection system at the flare tip for the purpose of improving combustion and thereby eliminating smoking conditions.  HOVENSA reports that the facility PTE for all eight flares is as follows: 1200 tpy SO2, 1897 tpy NOx and negligible emissions of PM.  For all the flares, including those subject to BART, HOVENSA's best estimate of the PTE for each flare is that emissions are divided approximately equally among each flare, as follows: 150 tpy SO2, 237 tpy NOx and negligible emissions of PM.  However, HOVENSA also reports that the PTE emissions are much higher than actual emissions which have the following average emissions for the five flares subject to BART: 1.46 tpy SO2, 6.7 tpy NOx and 1.0 typ PM.
The June 2011 CD requires that each of the five BART flares subject to the NSPS Part 60 subparts J and Ja requirements implement "flare gas recovery" to comply with the CD.  Flare gas recovery is a system to reduce SO2 emissions by the installation of compressors on the flare line to recycle the flare gas back into process units for removal of H2S.    Since the CD will further reduce SO2 emissions and actual emissions from the flares are very low and EPA is not aware of any desulfurization technologies to treat flare gas emissions, EPA is proposing that current operations are considered as BART for both SO2 and PM.  Furthermore, as discussed above for other units (boilers, turbines etc) subject to BART, any reduction of NOx emissions would not have any significant impact on visibility and therefore, EPA is proposing that current operations are considered as BART for NOx.
Therefore, EPA is proposing that current operations without any new controls of SO2, NOx and PM emissions represent BART for the five flare units subject to BART.

Water Intake Pumps and Desalination Water Pump
HOVENSA owns and operates four Water Intake Pumps and one Desalination Water Pump and each combusts either diesel or No. 2 fuel oil.  EPA has determined that each of the Water Intake Pumps (PD-1062 through PD-1065) and the Desalination Water Pump (PD-1620) are subject to BART.  HOVENSA has confirmed that each of these pumps is an emergency standby pump that is used only when there is a complete power failure at the refinery.  HOVENSA reports that actual emissions are negligible and PTE emissions are small.  EPA determined that the average PTEs are as follows: 1.8 tpy SO2, 38 tpy NOx, and 2.7 tpy PM.  The pumps normally in use are electric driven pumps and therefore have no air pollutant emissions.
Since these five pumps are used very infrequently and actual emissions are negligible it is EPA's judgment that any detailed cost analysis would conclude that implementation of any technologies for controlling emissions of SO2, NOx or PM are not cost effective.  Therefore, EPA is proposing that current operation represents BART for these five pumps subject to BART.

BART Determinations
In summary, EPA's BART evaluation of the boilers, turbines, process heaters, and several other source categories that are subject to BART at HOVENSA has determined that no additional control for SO2, NOx and PM emissions is consistent with BART.  Most stacks are not amenable to cost effective controls. EPA is proposing that current operations represent BART for HOVENSA.  As such, EPA's Federal plan includes the establishment of emission limits for SO2, NOx and PM equivalent to the potential to emit (PTE) for each unit subject to BART, as derived from HOVENSA's permit limit conditions.  EPA's Federal plan includes these PTE limits in the spreadsheets found in the Attachments to the FIP.
For the stacks that have low cost effectiveness for controls for NOx, EPA further analyzed the contribution of various chemical species and components on the visibility impacts. The contribution of NOx compounds from all potential BART sources at HOVENSA to visibility impairment on the average 98[th] percentile day is about a 0.09 dv visibility impact at St. John and 0.91 dvfor Hassel Island from all HOVENSA units subject to BART.  The implementation of any new NOx controls (even SNCR or SCR) would not result in sufficient improvements in visibility on St. John.  Therefore, EPA is determining that current operations of the BART-eligible sources at HOVENSA, including the nine turbines, are considered BART for controlling NOx emissions.
BART Analysis for WAPA Facilities on St. Croix and St. Thomas
WAPA power plants on St. Croix and St. Thomas are potential BART sources, with emission sources that are large enough to qualify for BART and were built at during the BART-eligible period. However, the impact of the WAPA power plant on St. Croix and the WAPA power plant on St. Thomas have an impact of 0.09 and 0.04 dv, respectively, for the average 98[th] percentile metric, on visibility at the IMPROVE monitor on St. John. An analysis of potential controls is listed in the accompanying tables. However, the improvement in visibility from these reductions would be even less than the less than 0.1 dv total impact of these potential BART sources, so EPA has determined that they are not eligible for BART controls, due to how little they add to improving visibility at the National Park in St. John.
BART Determinations including Other Types of Standards
As allowed by 40 CFR §51.308(e)(1)(iii) of the Regional Haze Rule the EPA has determined in establishing BART that technological or economic limitations on the applicability of measurement methodology would make the imposition of an emission standard infeasible. A design, equipment, work practice, or other operational standard, or combination thereof can be prescribed to require the application of BART for each source. These standards, to the degree possible, set forth the emission reduction to be achieved by implementation of such design, equipment, work practice or operation, and provide for compliance by means that achieve equivalent results.
For this FIP, existing controls were determined to be BART.  No other standards were needed to determine that BART controls were not feasible.
Description of BART Alternative for Any Source
In section (e)(2) of the RHR provides that a state may opt to implement an emissions trading program or other alternative measure rather than to require sources subject to BART to install, operate, and maintain BART. To do so, the State must demonstrate that emissions trading program or other alternative measure will achieve greater reasonable progress than would be achieved through the installation and operation of BART. To make this demonstration, the State must submit an implementation plan containing the elements listed in Section (e)(2).
No alternative measures are available for the Virgin Islands FIP, since there are no sources in other states that affect the Virgin Islands' Class I area.
Schedule for BART Implementation
As provided in 40 CFR §51.308(e)(1)(iv) BART must be in operation for each applicable source no later than five years after FIP approval. If these potential BART sources in the Virgin Islands were to be subject to BART, each would be required to install and operate BART as expeditiously as practicable but in no event later than five years after approval of the FIP or plan revision by EPA.
As provided in 40 CFR §51.308(e)(1)(v), the Title V operating permits for BART sources must include a requirement that each source maintain the control equipment and establish procedures to ensure such equipment is properly operated and maintained. This requirement would have been included in the Title V operating permit for each source subject to BART.

LONG-TERM STRATEGY
Section 51.308(d)(3) of 40 CFR part 51 requires the Virgin Islands to submit a long-term strategy that addresses regional haze visibility impairment for each mandatory Class I Federal area within and outside the Territory that may be affected by emissions from within the Territory. The long-term strategy must include enforceable emissions limitations, compliance schedules, and other measures necessary to achieve the reasonable progress goals established for the Class I.
This section describes how the FIP for the Virgin Islands meets the long-term strategy requirements. This long-term strategy addresses visibility impairment for the Virgins Islands National Park, which is the only Class I Area that is affected by emissions from within the Virgin Islands.
The long-term strategy described below includes enforceable emissions limitations, compliance schedules, and other measures necessary to achieve the reasonable progress goals established for the Class I to the extent that it is reasonable for the Virgin Islands (or EPA on its behalf) to adopt them before the date this FIP is finalized. Additional measures may be reasonable to adopt at a later date after further consideration and review. In this FIP, EPA is using existing measures to address reasonable progress.
Overview of the Long-Term Strategy Development Process
Section 51.308(d)(3)(iii) of 40 CFR part 51 requires us to document the technical basis for the State's/Tribe's apportionment of emission reductions necessary to meet reasonable progress goals in each Class I area affected by the Territory's emissions.
Modeling shows that Puerto Rico, the portion of the United States nearest to the Virgin Islands, does not affect visibility in the Class I area of the Virgin Islands National Park on St. John. We demonstrated this using dispersion modeling for a representative major source, which we located on the closest point on Puerto Rico to simulate the maximum possible impact on visibility in the Virgin Islands. The modeling predicts a less than 0.01 DV impact from a potential major source on Puerto Rico, so sources or groups of sources in the continental United States, which is much further away from the Virgin Islands than Puerto Rico, will not have an impact on visibility in the Virgin Islands.
 The trajectory and modeling results show that there may be some small effect from international sources (e.g., Antigua, St. Martin, British Virgin Islands); reductions from these sources would be a matter of international policy. Emissions from natural sources (e.g., Saharan Dust, Montserrat Volcano), cannot be controlled. Therefore, the ability of the Virgin Islands to coordinate emission reductions from sources on a regionwide scale is limited.
Because of this limitation, this FIP for the Virgin Islands relies on reductions that will occur in the Virgin Islands to achieve reasonable progress toward improving visibility in the Virgin Islands National Park. The following sections discuss the pollutants, source regions, and types of sources considered in developing this long-term strategy to assure the attainment of reasonable progress goals.
Emission Reductions Due to Ongoing Air Pollution Programs
Section 51.308(d)(3)(v)(A) of 40 CFR part 51 requires State/Tribes to consider emission reductions from ongoing pollution control programs. In developing its Long Term Strategy, the Virgin Islands FIP considered emission control programs being implemented between the baseline period and 2018, as discussed below. However, the effect of these programs, except for the HOVENSA consent decree and emission reductions from ocean vessels, were not included in the modeling, since EPA and VIDPNR do not have sufficient information on these source categories and how they will change by 2018. In addition, the remoteness of the Virgin Islands, especially the island of St. John (which is mostly a National Park), makes it difficult to project the effects of vehicle turnover and improvements to diesel engine fleets. Thus, these measures are included as possible contributors to improved visibility for the National Park on St. John.
Other Point Source Controls Expected by 2018 Due to Ongoing Air Pollution Control Programs
Point source controls applicable to the Virgin Islands include the following:
EPA's Refinery Enforcement Initiative. Since March 2000, the EPA has reached settlements with 29 U.S. companies responsible for 90 percent of petroleum refining in the nation. Through multi-issue, multi-facility settlements or detailed investigations and aggressive enforcement, this national initiative addresses the most significant Clean Air Act compliance concerns affecting the petroleum refining industry. HOVENSA, LLC was one such company that entered into a settlement with the EPA for its refinery on St. Croix. EPA's settlements require significant reductions of SO2 and nitrogen oxide, as well as emission reductions of benzene, VOCs, and particulate matter.
VOC 2-, 4-, 7-, and 10-year MACT Standards. Various point source MACTs and associated emission reductions were implemented in many parts of the United States, but were not considered in the development of projection emissions inventory for the Virgin Islands.
Combustion Turbine MACT. The projection inventories do not include the NOx co-benefit effects of the MACT regulations for Gas Turbines or stationary Reciprocating Internal Combustion Engines, which the EPA estimates to be small compared to the overall inventory.
Industrial Boiler/Process Heater/RICE MACTs. The EPA issued final rules to substantially reduce emissions of toxic air pollutants from industrial, commercial and institutional boilers, process heaters and from stationary reciprocating internal combustion engines (RICE). These rules reduce emissions of a number of toxic air pollutants, including hydrogen chloride, manganese, lead, arsenic and mercury by 2013. This rule also reduces emissions of NOx and VOCs in conjunction with the toxic air pollutant reductions (http://www.epa.gov/ttn/atw/rice/ricepg.html).
Controls on Non-road Sources Expected by 2018 due to Ongoing Air Pollution Control Programs
Non-road source controls that may be applicable to the Virgin Islands include the following:
Non-road Diesel Rule. This rule sets standards that will reduce emissions by more than 90 percent from non-road diesel equipment, and reduce sulfur levels by 99 percent from current levels in non-road diesel fuel starting in 2007. This step will apply to most non-road diesel fuel in 2010 and to fuel used in locomotives and marine vessels in 2012 (http://www.epa.gov/nonroad-diesel/). Reductions due to this program may reduce impairment to visibility by a small amount, but it was not modeled due to uncertainties in the emissions from this source category.
Mobile Source Controls Expected by 2018 due to Ongoing Air Pollution Control Programs
Mobile source controls applicable to the Virgin Islands include the following:
Heavy Duty Diesel (2007) Engine Standard. EPA set a PM emissions standard for new heavy-duty engines of 0.01 grams per brake-horsepower-hour (g/bhp-hr), to take full effect for diesel engines in the 2007 model year. This rule also includes standards for NOx and non-methane hydrocarbons (NMHC) of 0.20 g/bhp-hr and 0.14 g/bhp-hr, respectively. These NOx and NMHC standards will be phased in together between 2007 and 2010 for diesel engines. Sulfur in diesel fuel must be lowered to enable modern pollution-control technology to be effective on these trucks and buses. EPA will require a 97 percent reduction in the sulfur content of highway diesel fuel from its current level of 500 parts per million (low sulfur diesel, or LSD) to 15 parts per million (ultra-low sulfur diesel, or ULSD) (http://www.epa.gov/otaq/highway-diesel/index.htm).
Tier 2 Motor Vehicle Standards. Tier 2 is a fleet averaging program, modeled after the California LEV II standards. Manufacturers can produce vehicles with emissions ranging from relatively high to zero, but the mix of vehicles a manufacturer sells each year must have average NOx emissions below a specified value. Tier 2 standards became effective in the 2005 model year (http://www.epa.gov/tier2/finalrule.htm).
Large Spark Ignition and Recreational Vehicle Rule. EPA has adopted new standards for emissions of NOx, hydrocarbons (HC), and carbon monoxide (CO) from several groups of previously unregulated non-road engines. Included in these are large industrial spark-ignition engines and recreational vehicles. Non-road spark-ignition engines are those powered by gasoline, liquid propane, or compressed natural gas rated over 19 kilowatts (kW) (25 horsepower). These engines are used in commercial and industrial applications, including forklifts, electric generators, airport baggage transport vehicles, and a variety of farm and construction applications. Non-road recreational vehicles include snowmobiles, off-highway motorcycles, and all-terrain vehicles. These rules were initially effective in 2004 and should be fully phased-in by 2012 (http://epa.gov/nonroad/2002/cleanrec-final.htm).
Reductions from these source categories are not estimated for modeling because of the uncertainties in the makeup of the emission inventories for these sources.
Source Retirement and Replacement Schedules
Section 51.308(d)(3)(v)(D) of 40 CFR part 51 requires us to consider source retirement and replacement schedules in developing reasonable progress goals. In January 2012, it was announced that the HOVENSA refinery would be ceasing refinery operations and converting to an oil storage terminal by mid-February of 2012. Modeling suggests the emissions from HOVENSA sources are responsible for 1.06 dv of visibility impairment in the Virgin Islands National Park at St. John. The closure of this facility would provide much of the reduction needed to meet reasonable progress target for 2018, although this FIP is not using these reductions because HOVENSA has not surrendered its emissions permits. So for the long-term plan, HOVENSA is modeled as if it continues to operate, but with the emission reductions agreed to in the consent decree.
Additional source retirements or replacements are not expected by 2018.  Any retirement and replacement must comply with existing SIP requirements including those pertaining to PSD and New Source Review.
Additional Reasonable Strategies
Section 51.308(d)(3) of 40 CFR part 51 requires Plans to include enforceable emissions limitations, compliance schedules, and other measures as necessary to achieve the reasonable progress goals established by States/Tribes with Class I areas. The plan must include reasonable measures and identify the visibility improvement that will result from those measures.
Since existing measures and agreements are the reasonable measures for this FIP for the Virgin Islands, the Section 51.308(d)(3) compliance schedules are not need for this Plan.
As discussed in the next section, additional controls for this long-term strategy are limited, in part, due to the compressed schedule for this FIP.
Analysis of the Four Statutory Factors
The CAA (Sec. 169A) requires that Haze Plans provide for reasonable progress toward attaining the goal of preventing any future, and remedying any existing impairment of visibility in mandatory Class I Federal areas. In determining reasonable progress, States shall consider the four factors listed below:
         * Costs of compliance
         * Time necessary for compliance
         * Energy and non-air quality environmental impacts of compliance
         * Remaining useful life of any potentially affected sources.
Regulations implementing this requirement have been promulgated in 40 CFR Part 51, Subpart P  -  Protection of Visibility. Section 51.308 specifically addresses the regional haze program requirements. Guidance on implementing the reasonable progress requirements have been developed by the EPA, Guidance for Setting Reasonable Progress Goals under the Regional Haze Program, revised June 1, 2007.
In judging the adequacy of visibility improvement, the EPA has considered all current regulations and programs, and then determined the amount of additional improvement that may be necessary to represent reasonable progress. For the Virgin Islands, visibility improvements will not reach the reasonable progress goal, but existing controls are all that can reasonably be done to improve visibility in the first period ending in 2018.
With respect to the four-factor analysis, the implementation of any additional control strategies is hampered by the compressed schedule that this FIP was developed under. Sources would have only a few years to comply with any additional control programs. Based on timeframes presented in regional haze SIPs for other States, this would be a minimum amount of time needed for the simplest of additional strategies. It is unreasonable to expect any additional control in this period.
Best Available Retrofit Technology
BART controls at sources potentially subject to BART are identified in Section 6 of this FIP.  EPA has determined BART to be existing controls, as additional controls are neither cost effective nor to have much impact on improving visibility in the National Park.
Changes to Emissions by 2018
The emissions inventory for the Virgin Islands Haze Plan has been completed for the island of St. John. Due to the small impact from sources on St. Thomas and St. Croix, except for HOVENSA, and the emerging state of the emissions inventory for the Virgin Islands, the official emission inventory for regional haze plan will be tabulated for sources on the island of St. John and surrounding waters. Emissions change from the 2004 base year to the 2018 inventory for the island of St. John due to reduced emissions from marine vessels. While these reductions in marine vessel emissions are not part of the enforceable plan for the Virgin Islands Haze Plan, they are included as EPA anticipates that the marine vessel controls will be in place before 2018.  Other emission reductions are possible, such as introduction of newer, cleaner motor vehicles and reduced sulfur in fuel and controls on off-road vehicles. But these reductions in vehicle emissions are hard to quantify for a remote location like St. John, so emission reductions from these sources will not be quantified in the emission inventory for St. John for 2018.
Visibility on St. John will also be improved by the emission reductions from the consent decree at HOVENSA. This change in emissions is tabulated separately from the emission inventory for St. John, as they occur on the island of St. Croix, not on St. John. Other emissions on St. Croix and St. Thomas are not anticipated to change or the change will be too small to affect visibility on St. John, so this haze plan will not include them in the emissions summaries.  A summary of these changes is in emissions of SO2 is provided in Table 7-1, NOx in Table 7-2, and PM in Table 7.3 for the island of St. John. HOVENSA emission changes from the consent decree are in Table 7.4.
Table 7-1: Emissions from Point, Area and Mobile Sources on St. John, Virgin Islands (SO2 tpy)
                                 Source Sector
                                 Baseline 2002
                         2018 (with measures for RPG)
                                     Point
                                     43.11
                                     43.11
                                     Area
                                     0.05
                                     0.05
                                Non-Road Mobile
                                     17.89
                                     17.89
                                On-Road Mobile
                                     1.61
                                     1.61
                                Marine Vessels
                                     94.06
                                     14.11
                                     Total
                                    156.72
                                     76.77

Table 7-2: Emissions from Point, Area and Mobile Sources on St. John, Virgin Islands (NOx tpy)
                                 Source Sector
                                 Baseline 2002
                         2018 (with measures for RPG)
                                     Point
                                    477.66
                                    477.66
                                     Area
                                     3.69
                                     3.69
                                Non-Road Mobile
                                     2.07
                                     2.07
                                On-Road Mobile
                                     25.03
                                     25.03
                                Marine Vessels
                                    318.23
                                     63.65
                                     Total
                                    826.68
                                     572.1

Table 7-3: Emissions from Point, Area and Mobile Sources on St. John, Virgin Islands
(PM tpy)
                                 Source Sector
                                 Baseline 2002
                         2018 (with measures for RPG)
                                     Point
                                     34.33
                                     34.33
                                     Area
                                     38.32
                                     38.32
                                Non-Road Mobile
                                     1.93
                                     1.93
                                On-Road Mobile
                                     0.73
                                     0.73
                                Marine Vessels
                                     8.57
                                     1.28
                                     Total
                                     83.88
                                     76.59

Table 7-4: Emissions from HOVENSA (tons per year)

SO2
NOx
PM
EC*
HOVENSA Base 2002
12,778
26,362
2,207
22.1
HOVENSA Post Control 2018
9,318
21,331
2,192
21.9
* Elemental Carbon emissions were assumed to be 1/100 of total PM emissions.
These emissions are included in the modeling analysis to determine the improvement in visibility at the Class I area in the Virgin Islands.  Other emissions sources are described in the modeling analysis in the Appendix.

Additional Measures Considered
These sources include ferries, cruise ships, and cargo ships that dock at St. John. The Caribbean ECA (Emissions Control Area) emission reductions for ocean vessels are included in the future case modeling. Beginning in 2015, fuel used by all vessels operating in these areas cannot exceed 0.1 percent fuel sulfur (1,000 ppm). This requirement is expected to reduce PM and SOx emissions by more than 85 percent. Beginning in 2016, new engines on vessels operating in these areas must use emission controls that achieve an 80 percent reduction in NOx emissions. While these reductions are not enforceable as part of this FIP, EPA expects them to occur and they will be included in the reductions expected in the period through 2018.
Caribbean Emissions Control Area
The Caribbean ECA (Emissions Control Area) emission reductions for ocean vessels are included as an improvement in air quality for the future case modeling. Beginning in 2015, fuel used by all vessels operating in these areas cannot exceed 0.1 percent fuel sulfur (1,000 ppm). This requirement is expected to reduce PM and SOx emissions by more than 85 percent. Beginning in 2016, new engines on vessels operating in these areas must use emission controls that achieve an 80 percent reduction in NOx emissions. While these emission reductions were not developed specifically for this FIP, the use of the proper fuel and emission controls will be enforceable by EPA when this program goes into effect.  These emission reductions will result in 0.03 dv improvement in visibility on the twenty percent worst visibility days at the IMPROVE site on St. John.
Measures to Mitigate the Impacts of Construction Activities
Section 51.308(d)(3)(v)(B) of 40 CFR part 51 requires the Virgin Islands to consider measures to mitigate the impacts of construction activities.
As noted previously, the majority of the soils contribution to visibility impairment on the twenty percent worst days is attributable to transport of Saharan dust, and not necessarily local sources. In preparation for the next SIP revision in 2018, the EPA will work with VIDPNR to determine the effectiveness of better construction practices on St. John and quantify the contribution of construction activity to visibility impairment and possible mitigation strategies.
Agricultural and Forestry Smoke Management
Section 51.308(d)(3)(v)(E) of 40 CFR part 51 requires Haze Plans to consider smoke management techniques for the purposes of agricultural and forestry management in developing reasonable progress goals. The Virgin Islands has an open burning regulation.
Smoke Management Programs are only required when smoke impacts from fires managed for resource benefits contribute significantly to regional haze. The results of the emissions inventory on St. John indicate that emissions from agricultural, managed, and prescribed burning are small sources of pollution. It is unlikely that fires for agricultural or forestry management cause large impacts on visibility in the Virgin Islands National Park. On rare occasions, when smoke from major fires degrades the air quality and visibility in the Virgin Islands. However, these fires are generally unwanted wildfires that are not subject to smoke management programs.
Enforceability of Emission Limitations and Control Measures
Section 51.308(d)(3)(v)(F) of 40 CFR part 51 requires Haze Plans to ensure that emission limitations and control measures used to meet reasonable progress goals are enforceable.
BART eligible sources have existing permits that are enforceable by EPA.
Federal measures, such as the Federal Motor Vehicle Control Program, are enforceable by EPA.
The marine vessel emission reductions under ECA are enforceable by EPA.
EPA will continue to work with the Virgin Islands to evaluate the measures included in the long-term strategy, especially if HOVENSA reopens.  EPA and the Virgin Islands will determine whether controls, particularly at HOVENSA, are reasonable to adopt and implement by 2018 and will evaluate these and other potential measures in preparation for the next revision of the haze plan in 2018.
EPA will require that if HOVENSA reopens its refinery, HOVENSA shall evaluate all of its emission points to determine if reasonable controls are available for those emission points.
Consultation on the Long-Term Strategy
Section 51.308(d)(3)(i) 40 CFR part 51 requires consultation with other States/Tribes to develop coordinated emission management strategies. This requirement applies both where emissions from the Virgin Islands are reasonably anticipated to contribute to visibility impairment in Class I areas outside the Virgin Islands and when emissions from other States/Tribes are reasonably anticipated to contribute to visibility impairment in Class I areas within the Virgin Islands.
As noted in Section 3, the Virgin Islands have little impact on visibility impairment in other States and other States have little to no impact on visibility impairment in Virgin Islands. Therefore, consultation was limited to interaction with EPA Region 2 and the FLMs. The coordination with FLMs on long-term strategy development is described in sections 3.3, 8.0 and 9.2 of this plan.

Reasonable Progress Goals
For each Class I area within the State/Tribe, 40 CFR 51.308 (d)(1) requires the state (in this case, EPA for the Virgin Islands) to establish reasonable progress goals (RPG) (expressed in deciviews) that provide for reasonable progress towards achieving natural visibility. The EPA released guidance on June 7, 2007 to use in setting reasonable progress goals. The goals must provide improvement in visibility for the most impaired days, and ensure no degradation in visibility for the least impaired days over the SIP period.
Under 40 CFR 51.308 (d)(1)(iv), consultation is required in developing reasonable progress goals. As discussed in Section 3, because of the Virgin Islands' remote location, there is little to no impact from the Virgin Islands on visibility on other Class I areas or impacts of other states on Virgin Islands National Park. As such, the Virgin Islands did not need to be consulted during the establishment of reasonable progress goals for other Class I Areas and other States were not consulted in the development of the RPG for the Virgin Islands. In lieu of coordination with other States, the required discussions about the RPG that occurred between EPA Region 2 officials, EPA Headquarters and the appropriate FLMs will suffice for consultation.
In developing the RPG, the Class I State must also consider four factors (cost, time needed, energy and non-air quality environmental impacts, and remaining useful life). This plan discusses the uniform rate of improvement, the improvement in visibility needed to achieve the RPG for 2018 and how the effect of the planned measures compare to the RPG for the period covered by the implementation plan.
Calculation of Uniform Rate of Progress
As a benchmark to aid in developing reasonable progress goals, EPA Region 2 compared the baseline visibility conditions to natural visibility condition in the Class I area and determined the uniform rate of visibility improvement (in deciviews) that would need to be maintained during each implementation period in order to attain natural visibility condition by 2064. Table 7-1 presents the baseline visibility, natural visibility, and required uniform rate of progress for the Virgin Islands National Park. Additional Class I areas are listed in Table 7-1 for comparison.
Table 8-1: Uniform Rate of Progress Calculation
                                 Class I Area
                  (2000-2004) Baseline Visibility (deciviews)
                               (20% Worst Days)
                         Natural Visibility Conditions
                               (20% Worst Days)
                Deciview Improvement Needed by 2018 (from 2004)
                   Total Deciview Improvement Needed by 2064
                     Uniform Rate of Improvement Annually
                          Virgin Island National Park
                                     17.02
                                     10.68
                                     1.48
                                     6.34
                                     0.11
                             Acadia National Park
                                     22.9
                                     12.4
                                      2.4
                                     10.5
                                     0.17
                             Brigantine Wilderness
                                     29.0
                                     12.2
                                      3.9
                                     16.8
                                     0.28
                           Everglades National Park
                                     22.3
                                     12.2
                                      2.4
                                     10.2
                                     0.17
                   Hance Camp at Grand Canyon National Park
                                     11.7
                                      7.0
                                      1.1
                                      4.6
                                     0.08

Both natural conditions and baseline visibility for the 5-year period from 2000 through 2004 were calculated in conformance with the alternative, updated method recommended by the IMPROVE Steering Committee. Progress toward the 2018 target will be calculated based on 5-year averages calculated in a nationally consistent manner consistent with EPA's Guidance for Tracking Progress Under the Regional Haze Rule (EPA-454/B-03-004, September 2003) as updated by the alternative method for calculating regional haze recommended by the IMPROVE Steering Committee.
	Based on a base case visibility for the twenty percent worst days of 17.02 DV and a natural background calculated for worst twenty percent days of 10.68 DV, the difference is the Reasonable Progress Goal for 2064: 6.34 DV. According to EPA's Regional Haze Rule, a reduction of 6.34 DV by 2064 is to be accomplished by reducing visibility impairment by at least the rate of uniform reduction in each of the ten-year period covered by the haze plans.  The reduction needed by 2018 from 2004 (14 years for the first period) is calculated thus: 6.34 dv divided by 60 and multiplied by 14 = 1.48dv.

Reasonable Progress Goals for the Class I Area in the State
In accordance with the requirements of 40 CFR Section 51.308(d)(1), this Regional Haze Plan establishes reasonable progress goals for the Class I area in the Virgin Islands for the period of the implementation plan. The RPG for the Virgin Islands for the twenty percent worst days is 1.48 dv, of which the modeling predicts that visibility will be improved by 0.16 dv for the first period ending in 2018.
The Clean Air Act's plan for reducing regional haze is twofold:  1) Set the natural visibility target and insure that every 10 years the Virgin Islands has a plan to reduce emissions enough to remain on track to meet the target, and 2) Find all reasonable reductions in emissions that reduce visibility in the protected area. There is a tremendous amount of uncertainty in estimating how much of the Virgin Islands' visibility impairment is due to natural sources, and this plan has used default natural background concentrations, and not tried to adjust for the effects of Saharan Dust or other natural sources. It is likely that the effects of dust from the Sahara Desert overwhelm the effects of local sources on visibility in the Virgin Islands National Plan in a way not seen in any other part of the United States, since the Virgin Islands are nearer to Africa than any other location in the United States.
So, this plan determines the amount of emission reductions for the first plan period through 2018 based on the application of reasonably available emission reductions from sources that affect visibility in the Virgin Islands National Park on St. John.
In order to be on track to improve visibility to meet the CAA goal of reaching natural visibility levels, this plan estimates the amount of progress needed by 2018 based on the calculated natural level of visibility. In the case of the Virgin Islands, the emission reductions do not improve visibility to meet the reasonable progress goal line for 2018. However, the amount of progress estimate for 2018 may be an overestimate due to the underestimation of natural visibility conditions. This calculation does not include the full impact of Saharan Dust and other natural emissions that interfere with visibility. Therefore, this plan will focus on obtaining the maximum amount of reasonable reductions. For the next 10 years' plan, EPA and the Virgin Islands Department of Natural Resources will need to develop better estimates of the natural background visibility in the Virgin Islands and adjust the goal accordingly, while still reducing emissions as much as reasonably possible in the meantime.
To determine the RPG in deciviews, EPA Region 2 prepared emissions data and conducted modeling before and after certain control measures. The control measures reflected in these reasonable progress goals include the Caribbean ECA and the HOVENSA Consent Decree.
Consideration of Other Air Quality Requirements
40 CFR 51.308(d)(1)(vi) of EPA's Clean Air Visibility Rules requires that reasonable progress goals represent at least the visibility improvement expected from implementation of other CAA programs during the applicable planning period.
As documented in the emissions inventory and long-term strategy sections of this FIP, the modeling that formed the basis for reasonable progress goals in the Virgin Islands National Park could not estimate how other programs required by the CAA reduce emissions. Further information can be found in those sections of this FIP.
Additional Reasonable Controls within Virgin Islands
A full list of all Federal control measures considered is presented in Section 7. No additional measures are determined to be reasonable for the Virgin Islands. Implementation of any measures that have not been reviewed would be hampered by the compressed schedule that this FIP was developed under. Sources would have little time to comply with any additional control programs recommended in this FIP. Based on timeframes presented by States in their regional haze SIPs, this is minimum amount of time needed for the simplest of additional strategies. It is unreasonable to plan for any additional control in this period.
Visibility Impacts of Additional Reasonable Controls
This section explains assumptions used to model the impact of potential control strategies and describes the combined potential visibility benefits of all the strategies based on CALPUFF modeling and emissions analysis. As with all modeling, emissions estimates and modeling results for 2018 entail uncertainty, and further evaluation may be conducted as part of the SIP report required in 5 years under 40 CFR 51.308(g).
Impacts of BART Controls in the Virgin Islands
As discussed in Section 5, the Virgin Islands have three facilities with units that potentially could be subject to BART. As explained in this FIP, no BART controls beyond existing controls are being proposed or adopted.
Impacts of other Federal Controls in the Virgin Islands
The implementation of low sulfur fuels in the non-road sector (i.e., marine vessels) under the Caribbean ECA will provide an 85 percent reduction in SO2 and an additional 80 percent reduction in NOx from this source sector. This represents a 0.03 deciview improvement on the twenty percent worst days.
The settlement reached with HOVENSA, LLC as a result of EPA's Refinery Enforcement Initiative will result in an estimated 15 percent reduction in SO2 and a 16 percent reduction in NOx from the facility. This represents a 0.13 deciview reduction on the twenty percent worst days.
Additional controls that will affect the Virgin Islands are noted in Section 6, but were not included in the modeling for calculating improvement to visibility in the Class I area because of the limited data available on emissions in the Virgin Islands. All of the measures laid out in Section 6 will contribute to reductions in anthropogenic emission that may further improve visibility conditions at the Virgin Islands National Park.
Results of Best and Final Modeling
The starting point for indicating progress achieved by measures included in this FIP is the 2000-2004 baseline visibility at affected Class I areas. To calculate the baseline visibility for affected Class I areas, using 2000-2004 IMPROVE monitoring data, the deciview value for the twenty percent best days in each year with adequate data were averaged together, producing a single average deciview value for the best days. Similarly, the deciview values for the twenty percent worst days in each year with adequate data were averaged together, producing a single average deciview value for the worst days.
In order to estimate the visibility impacts of the measures discussed above, the EPA combined CALPUFF modeling results and emissions scaling analysis to assess the visibility improvement in the Virgin Islands. Documentation of the CALPUFF modeling is contained in Appendix C. Based on currently available information, this analysis provides an estimate of visibility improvement that could be achieved by 2018 through reasonable measures described above.
Figure 7-1 illustrates the predicted visibility improvement by 2018 resulting from the implementation of the long-term strategy, where quantifiable. This improvement is compared to the Uniform Rate of Progress for affected Class I areas. The Virgin Islands are projected to fall short of the uniform rate of progress goal for 2018. However, emission reductions from several control methods noted in this section could not be quantified due to the limited emissions information for the Virgin Islands. EPA has included reasonable measures in this FIP. In addition, the emissions are not expected to increase impairment of best day visibility relative to the baseline.
In addition to improving visibility on the 20% worst visibility days, states are also required to protect visibility on the 20% best days at the Class I areas. EPA's calculations show that visibility on the 20% best days is projected to be protected in this first planning period at the Virgin Islands National Park as emission controls will decrease emissions though 2018.

Figure 8-1: Projected Progress Goals and Modeled Progress at Virgin Islands National Park
Demonstration that the Goals are based on Reasonable Controls
Section 51.308 (d)(1)(i)(A) of 40 CFR part 51 requires that in establishing reasonable progress goals for each Class I area, the Plan must consider the costs of compliance, the time necessary for compliance, the energy and non-air quality environmental impacts of compliance, and the remaining useful life of any potentially affected sources, and the SIP must include a demonstration showing how these factors were taken into consideration in setting the goal. These factors are sometimes termed the "four statutory factors," since their consideration is required by the Clean Air Act.
Focus on SO2
The conceptual model developed for the Virgin Islands indicated that the dominant anthropogenic contributor to visibility impairment in the Virgin Islands National Park was particulate sulfate formed from emissions of SO2. While other pollutants will need to be addressed in order to achieve the national visibility goals, SO2 is responsible for 19 percent of light extinction on the twenty percent worst days. Therefore, it is reasonable that the additional measures considered in setting the reasonable progress goals described in Section 9.3 required reductions of SO2 emissions. Because of the relative lack of anthropogenic emission sources in the Islands, natural interference with visibility, mostly due to Saharan Dust, predominates, but can't be controlled.
Contributing Sources
As discussed in Section 1, the Virgin Island's distance from major land areas with major sources of pollution limits the number of sources affecting their Class I area. The emission inventory in Section 4 shows that point sources on St. Thomas and St. Croix are significant sources of SO2 emissions.  Evaluation of these sources' emissions for reasonable controls is in section 5. The largest of these sources included potentially BART-eligible sources and the evaluation of BART controls is discussed in section 6. Potential BART controls were either not reasonable or had little impact on improving visibility in the Virgin Islands.

Consultation and Coordination
Regional Planning
In 1999, EPA and affected States/Tribes on the continental United States agreed to create five Regional Planning Organizations (RPOs) to facilitate interstate coordination on Regional Haze SIP/Tribal Implementation Plans. The RPOs and States/Tribes within each RPO are required to consult on the development of emission management strategies directed towards visibility improvement in affected Class 1 areas. The RPOs have also allowed States to pool resources and collectively develop information, such as emissions inventories and modeling, to support regional haze plans.
Because the Virgin Islands are separated from the continental United States by over a thousand miles, they were not included in any RPO. As a result, this plan was developed without the assistance that the multi-state RPOs typically provide. Because the Virgin Islands government could not leverage its resources by working with other states to lay the groundwork for the their regional haze plan, EPA has opted to work alongside the Virgin Islands' government to prepare this regional haze plan as a Federal Implementation Plan
State/Tribe and Federal Land Manager Coordination
Section 51.308(i) of 40 CFR requires coordination between States/Tribes and the Federal Land Managers (FLMs). EPA Region 2 has discussed the technical documents developed by EPA Region 2 and included in this FIP with the FLMs. EPA Region 2 has provided agency contacts to the FLMs as required. In the development of this plan, the FLMs were consulted in accordance with the provisions of 40 CFR 51.308(i)(2). EPA Region 2 has consulted via conference call meetings with the FLMs.  The National Park Service has expressed their understanding of the proposed plan and reserves the opportunity to comment during the comment period upon EPA's proposal of this FIP.  EPA, in consultation with the Virgin Islands Government, will respond to comments from the FLM in accordance with 40 CFR 51.308(i)(3). The FLM's comments and EPA's responses will be included in Appendix A of this plan.
Section 51.308(i)(4) of 40 CFR requires procedures for continuing consultation between the State/Tribe and FLMs on the implementation of the visibility protection program. The Virgin Islands and EPA Region 2 will consult with the FLM(s) on the status of the following implementation items:
   1. Implementation of emissions strategies identified in the FIP as contributing to achieving improvement in the worst-day visibility.
   2. Summary of major new source permits issued.
   3. Status of actions in the Virgin Islands to meet commitments for completing any future assessments or rulemakings on sources identified as likely contributors to visibility impairment, but not directly addressed in the most recent FIP revision.
   4. Any changes to the monitoring strategy or monitoring stations status that may affect tracking of reasonable progress.
   5. Work underway for preparing the 5-year review and / or 10-year revision.
   6. Items for FLMs to consider or provide support for in preparation for any visibility protection SIP revisions (based on a 5-year review or the 10-year revision schedule under EPA's RHR)
   7. Summary of topics discussion (meetings, emails, other records) covered in ongoing communications between the Virgin Islands Government, EPA and FLMs regarding implementation of the visibility program.
The consultation will be coordinated with the designated visibility protection program coordinators for the National Park Service.
EPA Region 2 and the Virgin Islands will continue to coordinate and consult with the FLMs during the development of future progress reports and plan revisions, as well as during the implementation of programs having the potential to contribute to visibility impairment in the mandatory Class I areas.

Comprehensive Periodic Implementation Plan Revisions
Pursuant to the requirements of 40 CFR 51.308(a) and (b), EPA Region 2 will implement this FIP to meet the requirements of EPA's Regional Haze rules that were adopted to comply with requirements set forth in the Clean Air Act. Elements of this Plan address the Core Requirements pursuant to 40 CFR 51.308(d) and the BART components of 40 CFR 50.308(e). In addition, this FIP addresses Regional Planning, State/Tribe and Federal Land Manager coordination, and contains a commitment to provide Plan revisions and adequacy determinations.
Section 51.308(f) of 40 CFR requires a State/Tribe to revise its regional haze implementation plan and submit a plan revision to EPA by July 31, 2018 and every 10 years thereafter. In accordance with the requirements listed in 40 CFR 51.308(f) of the Federal rule for regional haze, EPA expects the Virgin Islands government to revise and submit a regional haze implementation plan by July 31, 2018 and every 10 years thereafter.
In addition, 40 CFR 51.308(g) requires periodic reports evaluating progress towards the reasonable progress goals established for each mandatory Class I area. In accordance with the requirements listed in 40 CFR 51.308(g) of the Federal rule for regional haze, the EPA expects the Virgin Islands government to submit a report on reasonable progress every 5 years following the initial submittal of this FIP. The report will be in the form of a SIP revision submitted 5 years after FIP submission. The reasonable progress report will evaluate the progress made towards the reasonable progress goal for the mandatory Class I area located within the Virgin Islands. All requirements listed in 40 CFR 51.308(g) shall be addressed in the FIP revision for reasonable progress.
Section 51.308(d)(4)(v) of 40 CFR requires periodic updates of the emission inventory. The EPA expects that the Virgin Islands government will update and expand upon the existing inventory.

Commitment to Determine the Adequacy of the Existing Plan
As required by 40 CFR 51.308(h), depending on the findings of the 5-year progress report, required under 40 CFR 51.308(g), the EPA expects that the Government of the Territory of the Virgin Islands will take one of the following actions at the same time the 5-year progress report is submitted:
(1) If EPA and the Virgin Islands determine that the existing implementation plan requires no further substantive revision in order to achieve established goals for visibility improvement and emissions reductions, the EPA will make a negative declaration that further revision of the existing implementation plan is not needed.
(2) If EPA or the Virgin Islands determine that the implementation plan is or may be inadequate to ensure reasonable progress due to emissions from sources in another country, the EPA will work with the Virgin Islands to assess the amount of impairment from other counties and determine if consultation is needed with the other country or countries.
(3) If EPA or the Virgin Islands determines that the implementation plan is or may be inadequate to ensure reasonable progress due to emissions from sources within the Virgin Islands, and if reasonable measures are available, the EPA expects that the Virgin Islands will submit a revision to the implementation plan to address the plan's deficiencies within 1 year.
The findings of the 5-year progress report will determine which actions are appropriate and necessary.

SUMMARY OF THE FEDERAL PLAN FOR VISIBILITY IN THE NATIONAL PARK ON ST. JOHN IN THE UNITED STATES VIRGIN ISLANDS
EPA is adopting a Regional Haze Federal Implementation Plan to begin the process for reducing man-made interference with visibility to meet the Federal Regional Haze Rule's goal of not man-made pollution interfering with visibility by 2064.  This FIP also addresses coordination with the Virgin Islands Government and the National Park Service as Federal Land Manager for the Virgin Islands National Park.  EPA expects the Virgin Islands Government to determine if the Plan is working and to update the plan within five years and when the next plan is due in 2018.
	The EPA used models to calculate how much local air pollution has affected visibility in Virgin Islands National Park, and is implementing this plan to reduce regional haze in the National Park using controls already in place and on the way.
	Most of the interference with visibility in the Park is due to the effects of dust from the Sahara Desert. However, EPA developed this haze plan by evaluating the reasonableness and effectiveness of reducing emissions based on the amount of air quality improvement that would occur. Emission controls were not rejected because of their impact compared to the effects of natural sources of visibility reduction affecting the Caribbean, but because they would be too expensive, not practicable, or not improve visibility. We cannot count the improvement in visibility from the shutdown of HOVENSA in this Plan, as HOVENSA must give up their air quality permits before we can take credit for up to 1.04 dv in visibility improvement.

Table 12-1: Virgin Islands National Park Visibility Improvement Due to the FIP
Virgin Islands National Park

       IMPROVE Measured Visibility Impairment in for the 20% worst days
                                  (Deciviews)

         Modeled Visibility Impairment for 20% worst days (Deciviews)
                             All sources, 4 years
                              Measured Baseline
                                     17.02
                                     10.14
                         Calculated Natural Background
                                     10.68
                                       -
                            Progress Goal for 2064
                                     6.34
                                       -
                              2018 Goal / Modeled
                                     15.54
                                     9.98
                   Reduction 2004-2018:     Needed / Modeled
                                     1.48
                                     0.16

	In summary, EPA's calculated a progress goal of improving visibility by 1.48 dv.  The air quality improvements from the HOVENSA consent decree and the expected reductions in marine vessel emissions are modeled as a reduction of 0.16 dv. A number of measures, mostly related to motor vehicle emissions, are not quantifiable and no other measures were cost effective on a dollar per ton basis or they did not improve visibility very much.
	EPA expects that the Virgin Islands' Government will determine if local action can reduce impacts of local sources on visibility in the Virgin Islands. In addition, before the HOVENSA refining facility on St. Croix reopens, it will first need to reevaluate its emissions to determine if reasonable controls should be implemented. The methods in EPA's Regional Haze Rule should be a useful guide to a successful evaluation of reasonable measures.


[Federal Register Volume 75, Number 224 (Monday, November 22, 2010)]
[Notices]
[Page 71101]
[FR Doc No: 2010-29303]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. CP11-28-000]

Monroe Gas Storage Company, LLC; Notice of Application

November 12, 2010.
    Take notice that on November 12, 2010, Monroe Gas Storage Company,
LLC (Monroe), 3773 Cherry Creek North Drive, Suite 1000, Denver, CO
80209, filed pursuant to Section 7(c) of the Natural Gas Act and the
Commission's regulations thereunder, an abbreviated application for an
amendment to its certificate of public convenience and necessity
authorizing Monroe to make changes to the certificated design of the
Monroe Gas Storage Project.
    Specifically, Through this Application, Monroe seeks authorization
to (1) change the location of the Well MGS-4 surface facilities to
another existing Project well pad, (2) move the Well MGS-9 surface
facilities to a different location on the currently authorized well
pad, and (3) modify the Project's water disposal facilities by adding a
water disposal well--Monroe Water Disposal 1 (``MWD-1''). In
conjunction with the relocation of Wells MGS-4-E-V and MGS-9-E-V,
Monroe also proposes to relocate the bottom hole location of the wells
and redesignate these wells as Wells MGS-4-E-D and MGS-9-ED.
    Monroe states that the proposed amendment will not change its
currently certificated authority to provide about 12.0 billion cubic
feet (Bcf) of high-deliverability working gas storage capacity, with
about 4.46 Bcf of base gas. Nor is any change proposed in Monroe's
certificated capability for receiving and injecting gas at maximum
rates of up to 445 million cubic feet per day (MMcf/d) and withdrawing
and delivering gas at maximum rates of up to 465 MMcf/d.
    Any questions regarding the application should be directed to Fred
Witsell, Monroe Gas Storage Company, LLC, 3773 Cherry Creek North
Drive, Suite 1000, Denver, CO 80209,<PHONE_NUMBER>, or Erik J.A.
Swenson, Fulbright & Jaworski L.L.P, 801 Pennsylvania Avenue, NW.,
Washington, DC 20004-2623,<PHONE_NUMBER>.
    There are two ways to become involved in the Commission's review of
this project. First, any person wishing to obtain legal status by
becoming a party to the proceedings for this project should, on or
before the comment date stated below, file with the Federal Energy
Regulatory Commission, 888 First Street, NE., Washington, DC 20426, a
motion to intervene in accordance with the requirements of the
Commission's Rules of Practice and Procedure (18 CFR 385.214 or
385.211) and the Regulations under the NGA (18 CFR 157.10). A person
obtaining party status will be placed on the service list maintained by
the Secretary of the Commission and will receive copies of all
documents filed by the applicant and by all other parties. A party must
submit 7 copies of filings made with the Commission and must mail a
copy to the applicant and to every other party in the proceeding. Only
parties to the proceeding can ask for court review of Commission orders
in the proceeding.
    However, a person does not have to intervene in order to have
comments considered. The second way to participate is by filing with
the Secretary of the Commission, as soon as possible, an original and
two copies of comments in support of or in opposition to this project.
The Commission will consider these comments in determining the
appropriate action to be taken, but the filing of a comment alone will
not serve to make the filer a party to the proceeding. The Commission's
rules require that persons filing comments in opposition to the project
provide copies of their protests only to the party or parties directly
involved in the protest.
    Persons who wish to comment only on the environmental review of
this project should submit an original and two copies of their comments
to the Secretary of the Commission. Environmental commentors will be
placed on the Commission's environmental mailing list, will receive
copies of the environmental documents, and will be notified of meetings
associated with the Commission's environmental review process.
Environmental commentors will not be required to serve copies of filed
documents on all other parties. However, the non-party commentors will
not receive copies of all documents filed by other parties or issued by
the Commission (except for the mailing of environmental documents
issued by the Commission) and will not have the right to seek court
review of the Commission's final order.
    The Commission strongly encourages electronic filings of comments,
protests and interventions in lieu of paper using the ``eFiling'' link
at http://www.ferc.gov. Persons unable to file electronically should
submit an original and 14 copies of the protest or intervention to the
Federal Energy regulatory Commission, 888 First Street, NE.,
Washington, DC 20426. This filing is accessible on-line at http://www.ferc.gov, using the ``eLibrary'' link and is available for review
in the Commission's Public Reference Room in Washington, DC. There is
an ``eSubscription'' link on the Web site that enables subscribers to
receive e-mail notification when a document is added to a subscribed
docket(s). For assistance with any FERC Online service, please e-mail
FERCOnline<EMAIL_ADDRESS>or call<PHONE_NUMBER> (toll free). For
TTY, call<PHONE_NUMBER>.
    Comment Date: November 22, 2010.

Kimberly D. Bose,
Secretary.
[FR Doc. 2010-29303 Filed 11-19-10; 8:45 am]
BILLING CODE 6717-01-P


[Federal Register Volume 88, Number 210 (Wednesday, November 1, 2023)]
[Notices]
[Pages 75002-75003]
[FR Doc No: 2023-24120]

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DEPARTMENT OF HEALTH AND HUMAN SERVICES

Food and Drug Administration

[Docket No. FDA-2023-N-4319]

Determination That CALCIUM DISODIUM VERSENATE (Edetate Calcium
Disodium) Injection, 200 Milligrams per Milliliter, and Other Drug
Products Were Not Withdrawn From Sale for Reasons of Safety or
Effectiveness

AGENCY: Food and Drug Administration, HHS.

ACTION: Notice.

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

SUMMARY: The Food and Drug Administration (FDA or Agency) has
determined that the drug products listed in this document were not
withdrawn from sale for reasons of safety or effectiveness. This
determination means that FDA will not begin procedures to withdraw
approval of abbreviated new drug applications (ANDAs) that refer to
these drug products, and it will allow FDA to continue to approve ANDAs
that refer to the products as long as they meet relevant legal and
regulatory requirements.

FOR FURTHER INFORMATION CONTACT: Stacy Kane, Center for Drug Evaluation
and Research, Food and Drug Administration, 10903 New Hampshire Ave.,
Bldg. 51, Rm. 6236, Silver Spring, MD 20993-0002,<PHONE_NUMBER>,
[email protected].

SUPPLEMENTARY INFORMATION: Section 505(j) of the Federal Food, Drug,
and Cosmetic Act (FD&C Act) (21 U.S.C. 355(j)) allows the submission of
an ANDA to market a generic version of a previously approved drug
product. To obtain approval, the ANDA applicant must show, among other
things, that the generic drug product: (1) has the same active
ingredient(s), dosage form, route of administration, strength,
conditions of use, and (with certain exceptions) labeling as the listed
drug, which is a version of the drug that was previously approved and
(2) is bioequivalent to the listed drug. ANDA applicants do not have to
repeat the extensive clinical testing otherwise necessary to gain
approval of a new drug application (NDA).
    Section 505(j)(7) of the FD&C Act requires FDA to publish a list of
all approved drugs. FDA publishes this list as part of the ``Approved
Drug Products With Therapeutic Equivalence Evaluations,'' which is
generally known as the ``Orange Book.'' Under FDA regulations, a drug
is removed from the list if the Agency withdraws or suspends approval
of the drug's NDA or ANDA for reasons of safety or effectiveness or if
FDA determines that the listed drug was withdrawn from sale for reasons
of safety or effectiveness (21 CFR 314.162).
    Under Sec.  314.161(a) (21 CFR 314.161(a)), the Agency must
determine whether a listed drug was withdrawn from sale for reasons of
safety or effectiveness: (1) before an ANDA that refers to that listed
drug may be approved, (2) whenever a listed drug is voluntarily
withdrawn from sale and ANDAs that refer to the listed drug have been
approved, and (3) when a person petitions for such a determination
under 21 CFR 10.25(a) and 10.30. Section 314.161(d) provides that if
FDA determines that a listed drug was withdrawn from sale for safety or
effectiveness reasons, the Agency will initiate proceedings that could
result in the withdrawal of approval of the ANDAs that refer to the
listed drug.
    FDA has become aware that the drug products listed in the table are
no longer being marketed.

----------------------------------------------------------------------------------------------------------------
                                             Active
  Application No.       Drug name        ingredient(s)       Strength(s)     Dosage form/route      Applicant
----------------------------------------------------------------------------------------------------------------
NDA 008922........  CALCIUM DISODIUM   Edetate Calcium    200 Milligrams     Injectable;        Bausch Health
                     VERSENATE.         Disodium.          (mg)/Milliliter    Injection.         US, LLC.
                                                           (mL).
NDA 011722........  TENUATE..........  Diethylpropion     25 mg............  Tablet; Oral.....  Nostrum Labs.,
                                        Hydrochloride.                                           Inc.
NDA 012546........  TENUATE DOSPAN...  Diethylpropion     75 mg............  Tablets, Extended- Do.
                                        Hydrochloride.                        Release; Oral.
NDA 019117........  FLUOCINONIDE.....  Fluocinonide.....  0.05%............  Cream; Topical...  Taro Pharms.
                                                                                U.S.A., Inc.
NDA 019796........  ELOCON...........  Mometasone         0.1%.............  Lotion; Topical..  Organon, LLC.
                                        Furoate.
NDA 020489........  ANDRODERM........  Testosterone.....  2 mg/24 hours; 4   Film, Extended     AbbVie Inc.
                                                           mg/24 hours.       Release;
                                                                              Transdermal.
NDA 020884........  AGGRENOX.........  Aspirin;           25 mg; 200 mg....  Capsule, Extended  Boehringer
                                        Dipyridamole.                         Release; Oral.     Ingelheim
                                                                                Pharms., Inc.
NDA 020903........  REBETOL..........  Ribavirin........  200 mg...........  Capsule; Oral....  Merck Sharp and
                                                                                Dohme Corp.
NDA 020907........  ACTIVELLA........  Estradiol;         0.5 mg; 0.1 mg...  Tablet; Oral.....  Amneal Pharms.,
                                        Norethindrone                                            LLC.
                                        Acetate.
NDA 020949........  ACCUNEB..........  Albuterol Sulfate  Equivalent to      Solution;          Mylan Specialty
                                                           (EQ) 0.021%        Inhalation.        LP.
                                                           Base; EQ 0.042%
                                                           Base.
NDA 021022........  PENLAC...........  Ciclopirox.......  8%...............  Solution; Topical  Valeant
                                                                                International
                                                                                Bermuda.
NDA 021449........  HEPSERA..........  Adefovir           10 mg............  Tablet; Oral.....  Gilead Sciences,
                                        Dipivoxil.                                               Inc.
NDA 022052........  ZYFLO CR.........  Zileuton.........  600 mg...........  Tablet, Extended   Chiesi USA, Inc.
                                                                              Release; Oral.
NDA 022511........  VIMOVO...........  Esomeprazole       EQ 20 mg Base;     Tablet, Delayed    Horizon
                                        Magnesium;         375 mg; EQ 20 mg   Release; Oral.     Medicines LLC.
                                        Naproxen.          Base; 500 mg.
NDA 022569........  LAZANDA..........  Fentanyl Citrate.  EQ 0.1mg Base; EQ  Spray, Metered;    BTcP Pharma,
                                                           0.3 mg Base; EQ    Nasal.             LLC.
                                                           0.4 mg Base.
NDA 202788........  SUBSYS...........  Fentanyl.........  0.1 mg; 0.2 mg;    Spray; Sublingual  Do.
                                                           0.4 mg; 0.6 mg;
                                                           0.8 mg; 1.2 mg;
                                                           1.6 mg.
NDA 213645........  DAPZURA RT.......  Daptomycin.......  500 mg/Vial......  Powder;            Baxter
                                                                              Intravenous.       Healthcare
                                                                                Corp.
----------------------------------------------------------------------------------------------------------------

    FDA has reviewed its records and, under Sec.  314.161, has
determined that the drug products listed were not withdrawn from sale
for reasons of safety or effectiveness. Accordingly, the Agency will
continue to list the drug products in the ``Discontinued Drug Product
List'' section of the Orange Book. The ``Discontinued Drug Product

List'' identifies, among other items, drug products that have been
discontinued from marketing for reasons other than safety or
effectiveness.
    Approved ANDAs that refer to the drug products listed are
unaffected by the discontinued marketing of the products subject to
these applications. Additional ANDAs that refer to these products may
also be approved by the Agency if they comply with relevant legal and
regulatory requirements. If FDA determines that labeling for these drug
products should be revised to meet current standards, the Agency will
advise ANDA applicants to submit such labeling.

    Dated: October 27, 2023.
Lauren K. Roth,
Associate Commissioner for Policy.
[FR Doc. 2023-24120 Filed 10-31-23; 8:45 am]
BILLING CODE 4164-01-P


[Federal Register Volume 83, Number 20 (Tuesday, January 30, 2018)]
[Rules and Regulations]
[Pages 4138-4139]
[FR Doc No: 2018-01681]

=======================================================================
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SECURITIES AND EXCHANGE COMMISSION

17 CFR Part 249

[Release No. 33-7424A; 34-38771A; 35-26733A; 39-2354A; IC-22727A]

Amendments to Forms and Schedules To Remove Voluntary Provision
of Social Security Numbers

AGENCY: Securities and Exchange Commission.

ACTION: Final rule; technical correction.

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SUMMARY: This document makes a technical correction to a form

amendment that was published in the Federal Register on July 1, 1997.
The Commission adopted revisions to forms and schedules filed under the
Securities Act of 1933, the Securities Exchange Act of 1934, related
provisions of the Investment Company Act of 1940 and the Public Utility
Holding Company Act of 1935, and the Trust Indenture Act of 1939, to
eliminate the portion of those forms that requests filers who are
natural persons to furnish their Social Security numbers. The 1997
amendment to Form MSD inadvertently omitted the removal of the second
of two references to Social Security numbers in the instructions to the
form.

DATES: Effective January 30, 2018.

FOR FURTHER INFORMATION CONTACT: Brice Prince, at<PHONE_NUMBER>,
Division of Trading and Markets, Securities and Exchange Commission,
100 F Street NE, Washington, DC 20549.

SUPPLEMENTARY INFORMATION: We are making a technical correction to Form
MSD \1\ under the Exchange Act.\2\
---------------------------------------------------------------------------

    \1\ 17 CFR 249.1100, Form MSD, application for registration as a
municipal securities dealer pursuant to rule 15Ba2-1 under the
Securities Exchange Act of 1934 or amendment to such application.
    \2\ 15 U.S.C. 78a et seq.
---------------------------------------------------------------------------

List of Subjects in 17 CFR Part 249

    Reporting and recordkeeping requirements, Securities.

Text of the Amendments

    For the reasons set out above, title 17, chapter II of the Code of
Federal Regulations is amended as follows:

PART 249--FORMS, SECURITIES EXCHANGE ACT OF 1934

0
1. The general authority citation for part 249 continues to read as
follows:

    Authority: 15 U.S.C. 78a et seq. and 7201 et seq.; 12 U.S.C.
5461 et seq.; 18 U.S.C. 1350; Sec. 953(b), Pub. L. 111-203, 124
Stat. 1904; Sec. 102(a)(3), Pub. L. 112-106, 126 Stat. 309 (2012);
Sec. 107, Pub. L. 112-106, 126 Stat. 313 (2012), and Sec. 72001,
Pub. L. 114-94, 129 Stat. 1312 (2015), unless otherwise noted.
* * * * *

0
2. Amend General Instruction M to Form MSD (referenced in Sec.
249.1100), by removing the text ``; social security numbers, if
furnished, will be used only to assist the Commission in identifying
applicants and, therefore, in promptly processing applications'' from
the end of the third sentence.

    Note: The text of Form MSD does not, and the amendments will
not, appear in the Code of Federal Regulations.

* * * * *

    Dated: January 24, 2018.
Brent J. Fields,
Secretary.
[FR Doc. 2018-01681 Filed 1-29-18; 8:45 am]
 BILLING CODE 8011-01-P