ATTACHMENT 1 September 24, 2003 Email from J. Lee of ICF " Lee, Jason" < JLee@ icfconsulting. com> 09/ 24/ 2003 10: 36 AM To: John Robbins/ DC/ USEPA/ US@ EPA, " Galef, Barry" < Bgalef@ icfconsulting. com> cc: Sikander Khan/ DC/ USEPA/ US@ EPA Subject: RE: Baseline NOx Emission Levels for Industrial Boilers Here are the baseline NOx emission levels.

Uncontrolled NOx levels for coal fired boilers ( not including fluidized bed and stoker fired boilers) firing bituminous coals ( range, average, and median values of NOx)  min:. 219 max:. 751 average:. 7146583 median:. 717 Uncontrolled NOx levels for coal fired boilers ( not including fluidized bed and stoker fired boilers) firing sub bituminous coals ( range, average, and median values of NOx)  min: .717 max:. 751 average: .72125 median:. 717 Uncontrolled NOx levels for gas fired boilers ( range, average, and median values of NOx)  min: .14 max: .386 average: .2459038 median:. 245 Uncontrolled NOx levels for oil fired boilers ( range, average, and median values of NOx)  min:. 219 max: .278 average:. 219486 median:. 219 Thank You!

J. JASON LEE ICF Consulting 9300 Lee Highway Fairfax, VA 22031 703.934.3578 jlee@ icfconsulting. com ATTACHMENT 2 Non EGU Inventory Summary NON EGU INVENTORY SUMMARY ( Reported 9/ 15/ 03)

The Emission Monitoring Branch ( EMB) of the Clean Air Markets Division ( CAMD) has developed an inventory of non electrical generating ( non EGU) units that are currently reporting under the NOX SIP Call, the Acid Rain and the Ozone Transport Commission programs. This inventory represents all non EGU units subject to reporting requirements under the various programs under Part 75 ( i. e. ARP, NOX SIP, OTC). The inventory is based on data submitted to CAMD for the 2nd quarter of 2003, as of August 15, 2003, which serves as the baseline for this inventory.

Procedure Units subject to reporting requirements under Part 75 must provide CAMD with quarterly electronic data report ( EDR) files which provide the following information:

  Unit Description Information ( unit ID, facility name, State, unit type, etc.)   Operational Characteristics ( fuels used, add on controls, hours of operation, etc.)   Monitoring Plan Information   QA/ QC test results   Hourly Emissions and Heat Input ( NOX, CO2, SO2)

This information is quality assured by EMB and Market Operations Branch ( MOB) to verify that the data is accurate and that it meets all regulatory requirements.

Due to the large amount of data ( hourly data for a 3 month period), EMB has developed a specific procedure in creating this inventory. This procedure consists of: ( 1) segregating all reporting data between EGUs and non EGUs, ( 2) collecting and sorting identified source data for non hourly information such as, fuel type used, control technology, unit ID, etc., and ( 3) creating server queries to collect and summarize hourly data such as hours of operation, total heat input, pollutant emissions, etc. All collected data are then sorted to provide a cohesive inventory. It should be noted that the inventory is based solely on data submitted for the 2nd quarter of 2003. This quarter data was used due to the addition of many industrial sources subject to the NOX SIP rule, whose first reporting period was the 2nd quarter.

Results The resulting inventory includes a total of 280 units, which were identified as non EGU sources. Table 1 of this document provides a breakdown of these units by source category, and provides additional data as to what types of fuel are used by each unit, what NOX control the units have if any. As indicated in Table 1, the majority of all the non EGUs are Dry Bottom Wall Fired Boilers ( 50%). Turbines make up a small percentage of all non EGU units ( 9%). Table 1 also indicates that most units are coal fired ( 36%). However, process gas1 is the second most used fuel ( 26%) as might be expected from industrial sources. Finally, add on controls are present in 36% of all units, and most prevalent in the Dry Bottom Wall Fired boilers ( 46% of all controlled units).

1 Process gas is any gas derived from an industrial process, which can be used as a fuel, such as blast furnace gas from steel mill operations. Of the total of 280 non EGU units, only 78 units indicated any hours of operation during the 2nd quarter of 2003. Table 2 provides a breakdown of all units, which reported any hours of operation during the 2nd quarter of 2003. For these units the additional analyses of average NOX rate by fuel type ( for controlled and non controlled units) and average operating time by fuel type ( for all units) was conducted. As indicated in Table 2, for most fuels, the NOX emission rate ( lb/ Btu) is lower for controlled units except for the Dry Bottom Wall Fired boilers burning pipeline natural gas, process gas or residual oil. The reader should not however, that these numbers may not be representative as the 2nd quarter 2003 data since this is considered a practice year for many of these sources ( NOX SIP) and may not yet reflect carefully quality assured data. As more quarters of data are collected, better trends will be realized for these fuels and boiler types.

In addition to Tables 1 and 2, three charts are included which better illustrate the breakdown of the boiler data by source category and fuels burned.

Conclusions This inventory is based on actual reporting data by sources classified as non EGUs, and therefore, we expect it to be more accurate than surveys or general industrial sector data. Analysis of the data from this inventory has revealed important trend information for various types of units, fuels, and control technologies. As this inventory grows with additional quarterly information, the trends can be refined and extrapolated based on a larger data pool. Also, we hope that this inventory can be cross referenced with other government and industry inventories to include useful data such as fuel characteristics ( sulfur and ash mercury content) and other information that is not normally gathered via Part 75 requirements. We are in the process of analyzing whether this inventory can be cross referenced with the industrial boilers database that OAQPS has developed in support of the MACT rule and hope to be able t report on our findings shortly.

Prepared by: Manuel J. Oliva   EMB, CAMD Thuy Nguyen   EMB, CAMD September 15, 2003 Table 1   Total Non EGU's Category Cyclone Boiler Cell Burner Boiler Combined Cycle Turbine Circulating Fluidized Bed Boiler Combustion Turbine Dry Bottom Wall Fired Boiler Dry Bottom Turbo Fired Boiler Dry Bottom Vertically

Fired Boiler Cement Kiln Other Boiler Stoker Boiler Tangentially Fired Boiler Wet Bottom Wall Fired Boiler Total Number of Units 7 2 9 2 16 139 2 3 2 48 18 26 6 280 Unit Fuel Type Coal 5 1 0 2 0 39 2 0 2 8 18 18 6 101 Diesel 0 0 0 0 2 4 0 0 0 5 0 0 0 11 Natural Gas 0 0 0 0 6 4 0 0 0 4 0 0 0 14 Other Gas 1 1 2 0 0 7 0 0 0 0 0 1 0 12 Pipeline Natural Gas 0 0 5 0 8 22 0 0 0 12 0 1 0 48 Process Gas 1 0 2 0 0 49 0 3 0 13 0 4 0 72 Residual Oil 0 0 0 0 0 11 0 0 0 0 0 1 0 12 Unit Control Type CM 4 0 0 0 0 5 0 0 0 0 0 3 1 13 DLNB 0 0 4 0 8 0 0 0 0 0 0 0 0 12 H2O 0 0 0 0 5 0 0 0 0 0 0 0 0 5 LNB 0 0 0 0 0 29 0 3 0 2 1 0 0 35 LNBO 0 0 0 0 0 7 0 0 0 3 0 0 0 10 LNC1 0 0 0 0 0 0 0 0 0 0 0 7 0 7 LNC3 0 0 0 0 0 0 0 0 0 0 0 1 0 1 LNCB 0 1 0 0 0 0 0 0 0 0 0 0 0 1 O 0 0 0 0 0 0 0 0 1 1 0 2 0 4 OFA 0 0 0 0 0 0 0 0 0 0 1 1 0 2 SCR 0 0 0 0 0 4 0 0 0 0 0 0 0 4 SNCR 1 0 0 0 0 0 0 0 0 0 0 0 0 1 STM 0 0 2 0 1 0 0 0 0 0 0 0 0 3 Total NOx Controls 5 1 6 0 14 45 0 3 1 6 2 14 1 98 Table 2   Reporting Non EGU's Category Cyclone Boiler Cell Burner Boiler Combined Cycle Turbine Circulating Fluidized Bed Boiler Combustion Turbine Dry Bottom Wall Fired Boiler Dry Bottom Turbo Fired Boiler Dry Bottom Vertically

Fired Boiler Cement Kiln Other Boiler Stoker Boiler Tangentially Fired Boiler Wet Bottom Wall Fired Boiler Total Number of Units 5 1 6 2 5 29 0 0 0 10 5 14 1 78 Unit Fuel Type Coal 4 1 0 2 0 7 2 5 12 1 34 Diesel 0 0 0 0 2 0 0 0 0 0 2 Natural Gas 0 0 0 0 0 1 2 0 0 0 3 Other Gas 1 0 2 0 0 4 0 0 0 0 7 Pipeline Natural Gas 0 0 2 0 3 4 0 0 0 0 9 Process Gas 0 0 2 0 0 7 6 0 0 0 15 Residual Oil 0 0 0 0 0 6 0 0 1 0 7 Unit Control Type CM 4 0 0 0 0 0 0 0 3 1 8 DLNB 0 0 1 0 1 0 0 0 0 0 2 H2O 0 0 0 0 3 0 0 0 0 0 3 LNB 0 0 0 0 0 6 1 0 0 0 7 LNBO 0 0 0 0 0 5 0 0 0 0 5 LNC1 0 0 0 0 0 0 0 0 6 0 6 LNC3 0 0 0 0 0 0 0 0 0 0 0 LNCB 0 1 0 0 0 0 0 0 0 0 1 O 0 0 0 0 0 0 0 0 0 0 0 OFA 0 0 0 0 0 0 0 0 0 0 0 SCR 0 0 0 0 0 0 0 0 0 0 0 SNCR 0 0 0 0 0 0 0 0 0 0 0 STM 0 0 2 0 1 0 0 0 0 0 3 Total NOx Controls 4 1 3 0 5 11 1 0 9 1 35 Table 2   Reporting Non EGU's ( Continued)

Category Cyclone Boiler Cell Burner Boiler Combined Cycle Turbine Circulating Fluidized Bed Boiler Combustion Turbine Dry Bottom Wall Fired Boiler Dry Bottom Turbo Fired Boiler Dry Bottom Vertically

Fired Boiler Cement Kiln Other Boiler Stoker Boiler Tangentially Fired Boiler Wet Bottom Wall Fired Boiler Total Coal 0.1518 0.9615 0.6779 0.8674 0.4252 0.6167 Diesel Natural Gas 0.2455 0.1523 0.1989 Other Gas 0.1343 2.9854 0.1693 1.0963 Pipeline Natural Gas 0.0484 0.0484 Process Gas 0.1821 0.0265 0.1843 0.1309 Average NOx Rate by Fuel Type ( Non Controlled Units) Residual Oil 0.1808 0.2390 0.2099 Overall Average NOx Rate 0.1343 1.5837 0.1518 0.2720 0.3382 0.8674 0.3321 0.3835 Coal 0.5295 0.6919 0.4416 0.3642 0.4714 0.4997 Diesel 0.4135 0.4135 Natural Gas 0.0291 0.0291 Other Gas Pipeline Natural Gas 0.0324 0.0678 0.1234 0.0746 Process Gas 0.1108 0.1108 Average NOx Rate by Fuel Type ( Controlled Units) Residual Oil 0.2188 0.2188 Overall Average NOx Rate 0.5295 0.6919 0.0324 0.2406 0.2237 0.0291 0.3642 0.4714 0.2244 Coal 1,505.06 1,987.25 2,046.00 1,479.81 1,402.2 2 1,417.9 6 1,562.90 1,464.00 1,608.15 Diesel 10.71 10.71 Natural Gas 1,456.00 1,160.5 0 1,308.25 Other Gas 1,464.00 623.27 1,799.81 1,295.70 Pipeline Natural Gas 607.05 1,384.49 1,165.39 1,052.31 Process Gas 1,486.66 1,454.15 1,641.2 2 1,527.34 Average Operating Time by Fuel Type ( All Units) Residual Oil 1,675.64 476.25 1,075.95 Overall Average Operating Time 1,484.53 1,987.25 905.66 2,046.00 697.60 1,505.14 1,401.3 1 1,417.9 6 1,019.58 1,464.00 1,125.49 CHART 1 TOTAL NON EGUs BY FUEL ( 2Q  2003)

Total Unit Population  280 38%

4%

5%

4%

18%

27% 4%

Coal Diesel Natural Gas Other Gas Pipeline Natural Gas Process Gas Residual Oil 0 20 40 60 80 100 120 140 Cyclone Boiler Cell Burner Boiler Combined Cycle Turbine Circulating Fluidized Bed Boiler Combustion Turbine Dry Bottom Wall

Fired Boiler Dry Bottom Turbo

Fired Boiler Dry Bottom Vertically

Fired Boiler Cement Kiln Other Boiler Stoker Boiler Tangentially Fired Boiler Wet Bottom Wall

Fired Boiler CHART 2 TOTAL NON EGUs BY SOURCE CATEGORY ( 2Q  2003) Residual Oil Process Gas Pipeline Natural Gas Other Gas Natural Gas Diesel Coal CHART 3  REPORTING NON EGUs BY FUEL ( 2Q  2003)

Reporting Unit Population  78 44%

3%

4%

9%

12%

19% 9%

Coal Diesel Natural Gas Other Gas Pipeline Natural Gas Process Gas Residual Oil ATTACHMENT 3 SEPTEMBER/ OCTOBER EMAILS BETWEEN S. KHAN OF EPA AND J. STAUDT OF ANDOEVER TECHNOLOGY Jim Staudt < staudt@ AndoverT echnology. com>

10/ 24/ 2003 03: 18 PM Please respond to staudt To: Sikander Khan/ DC/ USEPA/ US@ EPA cc: Subject RE: NOx Reduction and Costs for LNB/ OFA Sikander,

I've attached two files. The one C_ 006_ ICF_ Transport_ memo was prepared specifically for the work I am doing for you, and you should read this one first. The other one, C_ 03_ 007 Technical Memorandum, is associated with other work I am doing for EPA under my ICF Contract, but has quite a bit of information that relates directly to the state of the art in coal combustion NOx controls. So, I am attaching that as well as supporting information. I will look forward to reviewing this material with you on Tuesday morning.

Best Regards,

Jim Staudt, Ph. D., CFA Andover Technology Partners phone: ( 978) 683 9599 staudt@ AndoverTechnology. com www. AndoverTechnology. com **** This e mail and any files transmitted with it are confidential and are intended for the named addressee( s) only. If you have received it by mistake, please let us know by e mail reply and delete it from your system; you may not copy this message, use it, or disclose its contents to anyone else. We have taken every reasonable precaution to keep our network free from viruses, but we can take no responsibility for any computer virus which might be transferred by way of this e mail. We would advise that you carry out your own virus checks before opening any attachment. ****

 Original Message From: Khan. Sikander@ epamail. epa. gov [ mailto: Khan. Sikander@ epamail. epa. gov] Sent: Wednesday, September 10, 2003 6: 22 AM To: Jim Staudt Subject: NOx Reduction and Costs for LNB/ OFA Jim,

Thank you very much for spending a considerable amount of time with me on NOx controls for industrial boilers. I am summarizing below the items we discussed. I will use these items to start developing the cost curves. Once you have been formally notified of this work, please use these numbers as a starting point. In the meantime, if something jumps at you, please let me know.

All numbers quoted below are for 3 sizes of industrial boilers: 100, 250, and 1000 MMBtu/ hr. As you would note, I have tweaked some of the numbers we discussed to fit the information I need to develop the cost curves. For coal, I would assume post retrofit unburned carbon increasing by 100%. For oil, with gas recirculation, I am assuming that there is no increase in the unburned carbon level ( could you please let me know, if you agree). I am also assuming that for both oil and gas, the gas recirculation system would be designed for a 20% gas recirculation rate.

Low NOx Burners/ Gas Recirculation for Gas Firing Use a NOx level of 0.1 lb/ MMBtu with Low NOx burners and 0.05 lb/ MMBtu with Low NOx burners and gas recirculation ( GR). Use $ 2,000/ MMBtu for the 1,000 MMBtu/ hr boiler and a factor of 0.3 to adjust the cost for the smaller boilers ( this is the cost for both the LNB and GR). Use half of the cost in Item 2 for Low NOx burner only.

Low NOx Burners/ Gas Recirculation for Oil Firing Use a NOx level of 0.35 lb/ MMBtu with Low NOx burners and 0.25 lb/ MMBtu with Low NOx burners and gas recirculation ( GR). Use $ 2,000/ MMBtu for the 1,000 MMBtu/ hr boiler and a factor of 0.3 to adjust the cost for the smaller boilers ( this is the cost for both the LNB and GR). Use half of the cost in Item 2 for Low NOx burner only.

Low NOx Burners/ OFA for Coal Firing Use a NOx level of 0.4 lb/ MMBtu ( for bituminous coal) and 0.3 ( for sub bituminous coal) with Low NOx burners and 0.3 lb/ MMBtu ( for bituminous coal) and 0.2 ( for sub bituminous coal) with Low NOx burners and overfire air ( OFA). Use $ 5,000/ MMBtu for a 350 MMBtu/ hr boiler and a factor of 0.3 to adjust the cost for the three study boilers ( this is the cost for LNB alone). For the overfire air, add $ 15/ KW to the cost in Item 2 above to come up with the cost of both LNB and OFA.

Sikander Khan US EPA Telephone: 202 564 9781 Fax: 202 564 1980 Email Address: khan. sikander@ epa. gov C_ 03_ 006_ ICF_ Transport_ memo. doc C_ 03_ 007_ Technical Memorandum. doc ( Note: The above two attachments are provided as Attachments .) ATTACHMENT 4 FEBRUARY 7, 2002, MEMORANDUM FROM D. SELLERS TO K. CULLIGAN MEMORANDUM TO: Kevin Culligan FROM: David Sellers RE: Pulverized Coal Units Achieving 0.21 to 0.30 lb NOx/ mmBtu DATE: February 7, 2002 This memo is a follow up to the earlier memo sent to you February 1, 2001, regarding pulverized coal units that had achieved an average NOx rate of 0.20 lb/ mmBtu in 2000 or in the first 3 quarters of 2001 without add on NOx control.

Tables are provided which identify pulverized coal units in two additional groups: units that achieved NOx rates of 0.21 through 0.25 lb/ mmBtu,, and units that achieved rates of 0.26 lb/ mmBtu through 0.30 lb/ mmBtu during the same 2000 or 2001 period. In addition the tables include NOx rates for previous years ( 1995  1999), the type of primary combustion related NOx control, and the primary type of coal burned.

The primary fuel type ( bituminous, subbituminous, or lignite) is identified for the units based on the FERC Form 423 database for 2000, and EPA's Hg ICR 1999 fuel data. The FERC data is at the plant level while the Hg ICR data is at the unit level. In cases where a plant or unit burned more than one type of coal, the coal type with the highest proportion was identified as the primary fuel.

The EIA 1605B Greenhouse Gas Voluntary Reporting database and a previous PQA literature review of boiler optimization projects were reviewed to identify if any of the units had installed boiler optimization software. None of the units listed here turned up in either source.

A preliminary internet search for boiler optimization at the 25 units achieving 0.21through 0.25 lb/ mmBtu found information on one unit, Crawford Unit 7 in Illinois. Midwest Generation had installed an ESC DAS and Expert Control software package on that unit in 2000. Table 1: Pulverized Coal Boilers Achieving a NOx Rate of 0.21  0.25 lb/ mmBtu, Sorted Based on 2001 NOx Rate State Plant Name ORIS Unit ID Boiler Type Primary NOx Controls 2000 NOX Rate lb/ mmBtu 2001 Thru Q3 Preliminary NOX Rate lb/ mmBtu* 1995_ 2000 Percent Reduction North Dakota Coal Creek 6030 1 T LNC3 0.21 0.21 66 Oklahoma Hugo 6772 1 WBF EIA_ LN 0.22 0.21 24 Wisconsin Weston 4078 3 T OFA 0.22 0.21 _ 9 Missouri Sikeston 6768 1 DB EIA_ LN 0.23 0.21 43 Texas Monticello 6147 3 DB EIA_ LN 0.24 0.21 3 Texas Martin Lake 6146 2 T U 0.29 0.21 16 Texas Martin Lake 6146 2 T U 0.29 0.21 16 Colorado Pawnee 6248 1 DB LNBO 0.21 0.22 21 Wisconsin Edgewater 4050 5 DB LNB 0.21 0.22 3 Delaware Edge Moor 593 4 T LNB 0.22 0.22 53 Colorado Comanche 470 1 T U 0.24 0.22 _ 10 Indiana R M Schahfer 6085 15 DB LNB 0.26 0.22 _ 9 Texas Limestone 298 LIM2 T OFA 0.28 0.22 44 Texas Gibbons Creek 6136 1 T LNC1 0.29 0.22 35 North Dakota Coal Creek 6030 2 T LNC3 0.22 0.23 69 Montana J E Corette 2187 2 T OFA 0.24 0.24 55 Kentucky Shawnee 1379 10 OB O 0.29 0.24 _ 10 Illinois Crawford 867 7 T U 0.3 0.24 1 South Carolina Cope Station 7210 COP 1 T LNC2 0.26 0.25 South Carolina Cope Station 7210 COP 1 T LNC2 0.26 0.25 Texas Coleto Creek 6178 1 T LNC1 0.24 0.27 38 Wisconsin South Oak Creek 4041 5 AF U 0.23 NA 7 Wisconsin South Oak Creek 4041 6 AF U 0.23 NA 7 Indiana Dean H Mitchell 996 11 DB U 0.26 NA 57 Indiana Dean H Mitchell 996 6 T EIA_ LNO V 0.26 NA 57 NOx Control Codes:

Code Description EIA LN EIA767 Data  Low NOx Burner Technology EIA LNOV EIA767 Data  Low NOx Burner Technology with Overfire Air EIA OV EIA767 Data  Overfire Air LNB Low NOx Burner Technology ( DB Boilers)

LNBO Low NOx Burner Technology with Overfire Air ( DB Boilers)

LNC1 Low NOx Burner Technology with Close Coupled Overfire Air ( T Boilers)

LNC2 Low NOx Burner Technology with Separated Overfire Air ( T Boilers)

LNC3 Low NOx Burner Technology with Close Coupled and Separated Overfire Air ( T Boilers)

OFA Overfire Air U Uncontrolled * South Oak Creek and Dean Mitchell units are served by a common stack. The preliminary 2001 data does not include a NOx rate apportionment for each of these units. Table 2: Pulverized Coal, 0.21 0.25 lb NOx/ mmBtu Units  Fuel Information State Plant Name ORIS Unit ID Boiler Type Primary NOx Controls 2000 NOX Rate lb/ mmBtu 2001 Thru Q3 Preliminary NOX Rate lb/ mmBtu FERC 423 Plant Primary Fuel 2000 FERC 423 Plant Fuel Origin BOM Dist FERC 423 Fuel Origin States Hg ICR 1999 Fuel Information Colorado Comanche 470 1 T U 0.24 0.22 SUB 19 WY Colorado Pawnee 6248 1 DB LNBO 0.21 0.22 SUB 19 WY Delaware Edge Moor 593 4 T LNB 0.22 0.22 BIT 8 WV Illinois Crawford 867 7 T U 0.3 0.24 SUB Indiana Dean H Mitchell 996 11 DB U 0.26 NA SUB 19 WY Indiana Dean H Mitchell 996 6 T EIA_ LNO 0.26 NA SUB 19 WY Indiana R M Schahfer 6085 15 DB LNB 0.26 0.22 SUB 19 WY Kentucky Shawnee 1379 10 OB O 0.29 0.24 BIT 17 CO Missouri Sikeston 6768 1 DB EIA_ LN 0.23 0.21 SUB 19 WY Montana J E Corette 2187 2 T OFA 0.24 0.24 SUB North Dakota Coal Creek 6030 1 T LNC3 0.21 0.21 LIG 21 ND North Dakota Coal Creek 6030 2 T LNC3 0.22 0.23 LIG 21 ND Oklahoma Hugo 6772 1 WBF EIA_ LN 0.22 0.21 SUB 19 WY South Carolina Cope Station 7210 COP1 T LNC2 0.26 0.25 BIT 8 KY South Carolina Cope Station 7210 COP1 T LNC2 0.26 0.25 BIT 8 KY Texas Coleto Creek 6178 1 T LNC1 0.24 0.27 BIT 17 CO Texas Gibbons Creek 6136 1 T LNC1 0.29 0.22 SUB 19 WY Texas Limestone 298 LIM2 T OFA 0.28 0.22 LIG 15 TX Texas Martin Lake 6146 2 T U 0.29 0.21 LIG 15 TX Texas Martin Lake 6146 2 T U 0.29 0.21 LIG 15 TX Texas Monticello 6147 3 DB EIA_ LN 0.24 0.21 LIG 15 TX Wisconsin Edgewater 4050 5 DB LNB 0.21 0.22 SUB 19 WY Wisconsin South Oak Creek 4041 5 AF U 0.23 NA SUB Wisconsin South Oak Creek 4041 6 AF U 0.23 NA SUB Wisconsin Weston 4078 3 T OFA 0.22 0.21 SUB 19 WY Table 3: Pulverized Coal, 0.21 0.25 lb NOx/ mmBtu Units  Average NOx Emission Rates 1995  2001Q3 State Plant Name ORIS Unit ID Boiler Type Primary NOx Controls 1995 NOX Rate lb/ mmBtu 1996 NOX Rate lb/ mmBtu 1997 NOX Rate lb/ mmBtu 1998 NOX Rate lb/ mmBtu 1999 NOX Rate lb/ mmBtu 2000 NOX Rate lb/ mmBtu 2001 Thru Q3 Preliminary NOX Rate lb/ mmBtu 1995_ 2000 Percent Reduction Colorado Comanche 470 1 T U 0.22 0.24 0.24 0.26 0.30 0.24 0.22 _ 10 Colorado Pawnee 6248 1 DB LNBO 0.27 0.23 0.21 0.21 0.23 0.21 0.22 21 Delaware Edge Moor 593 4 T LNB 0.46 0.31 0.31 0.32 0.31 0.22 0.22 53 Illinois Crawford 867 7 T U 0.30 0.31 0.33 0.31 0.32 0.3 0.24 1 Indiana Dean H Mitchell 996 11 DB U 0.60 0.39 0.30 0.32 0.29 0.26 NA 57 Indiana Dean H Mitchell 996 6 T EIA_ LNO 0.60 0.39 0.32 0.33 0.29 0.26 NA 57 Indiana R M Schahfer 6085 15 DB LNB 0.24 0.23 0.21 0.23 0.24 0.26 0.22 _ 9 Kentucky Shawnee 1379 10 OB O 0.26 0.25 0.28 0.29 0.26 0.29 0.24 _ 10 Missouri Sikeston 6768 1 DB EIA_ LN 0.41 0.43 0.39 0.72 0.24 0.23 0.21 43 Montana J E Corette 2187 2 T OFA 0.54 0.45 0.37 0.28 0.25 0.24 0.24 55 North Dakota Coal Creek 6030 1 T LNC3 0.63 0.58 0.56 0.58 0.31 0.21 0.21 66 North Dakota Coal Creek 6030 2 T LNC3 0.72 0.60 0.57 0.39 0.23 0.22 0.23 69 Oklahoma Hugo 6772 1 WBF EIA_ LN 0.29 0.32 0.26 0.29 0.32 0.22 0.21 24 South Carolina Cope Station 7210 COP1 T LNC2 0.00 0.00 0.00 0.00 0.27 0.26 0.25 South Carolina Cope Station 7210 COP1 T LNC2 0.00 0.00 0.00 0.00 0.27 0.26 0.25 Texas Coleto Creek 6178 1 T LNC1 0.39 0.40 0.36 0.28 0.24 0.24 0.27 38 Texas Gibbons Creek 6136 1 T LNC1 0.45 0.38 0.37 0.34 0.33 0.29 0.22 35 Texas Limestone 298 LIM2 T OFA 0.50 0.46 0.42 0.41 0.43 0.28 0.22 44 Texas Martin Lake 6146 2 T U 0.35 0.31 0.30 0.32 0.26 0.29 0.21 16 Texas Martin Lake 6146 2 T U 0.35 0.31 0.30 0.32 0.26 0.29 0.21 16 Texas Monticello 6147 3 DB EIA_ LN 0.25 0.24 0.24 0.22 0.22 0.24 0.21 3 Wisconsin Edgewater 4050 5 DB LNB 0.22 0.23 0.23 0.23 0.23 0.21 0.22 3 Wisconsin South Oak Creek 4041 5 AF U 0.25 0.23 0.24 0.28 0.26 0.23 NA 7 Wisconsin South Oak Creek 4041 6 AF U 0.25 0.24 0.24 0.29 0.26 0.23 NA 7 Wisconsin Weston 4078 3 T OFA 0.20 0.21 0.21 0.20 0.23 0.22 0.21 _ 9 Table 4: Pulverized Coal, 0.26 0.30 lb NOx/ mmBtu Units  Fuel Information Sorted Based on 2000 NOx Rate State Plant Name ORIS Unit ID Boiler Type Primary NOx Controls 2000 NOx Rate lb/ mmBtu 2001 Thru Q3 Preliminary NOx Rate lb/ mmBtu FERC 423 Plant Primary Fuel 2000 FERC 423 Plant Fuel Origin BOM Dist. FERC 423 Fuel Origin States Hg ICR 1999 Fuel Information Indiana Dean H Mitchell 996 11 DB 0.26 NA SUB 19 WY Indiana Dean H Mitchell 996 6 T EIA_ LNOV 0.26 NA SUB 19 WY Texas J T Deely 6181 1 T LNC1 0.26 NA SUB 19 WY Texas J T Deely 6181 2 T LNC1 0.26 NA SUB 19 WY Michigan Belle River 6034 2 DB LNB 0.26 0.26 SUB 22 MT Colorado Arapahoe 465 4 DVF LNBO 0.26 0.27 SUB 19 WY Arkansas Independence 6641 2 T OFA 0.26 0.29 SUB 19 WY Alabama James H Miller Jr 6002 2 DB 0.26 0.29 SUB 19 WY Colorado Valmont 477 5 T LNC3 0.26 0.29 BIT 17 CO Illinois Waukegan 883 7 T LNC1 0.26 0.3 SUB Michigan Dan E Karn 1702 2 DB LNBO 0.26 0.32 SUB 19 WY Michigan Belle River 6034 1 DB LNB 0.27 0.26 SUB 22 MT Michigan J R Whiting 1723 1 DB LNB 0.27 0.26 SUB/ BIT 19/ 08 WY/ WV Iowa Muscatine 1167 9 T LN 0.27 0.26 SUB 19 WY Kansas Quindaro 1295 2 DB EIA_ LN 0.27 0.26 SUB 19 WY Wyoming Laramie River 6204 2 DB LNB 0.27 0.27 SUB 19 WY Kansas Holcomb 108 SGU1 DB LNB 0.27 0.28 SUB 19 WY Georgia Scherer 6257 4 T EIA_ OV 0.27 0.28 SUB 19 WY Pennsylvania Eddystone 3161 2 T LNC3 0.27 0.29 BIT 02 PA Oklahoma GRDA 165 2 DB EIA_ LN 0.27 0.32 SUB 19 WY Georgia Yates 728 Y7BR T LNC2 0.28 0.26 BIT 08 KY, VA, WV Georgia Yates 728 Y6BR T LNC2 0.28 0.27 BIT 08 KY, VA, WV Arizona Cholla 113 4 T EIA_ OV 0.28 0.28 SUB 18 NM Arkansas Flint Creek 6138 1 DB LNB 0.28 0.29 SUB 19 WY Iowa Louisa 6664 101 DB EIA_ LN 0.28 0.29 SUB 19 WY Minnesota Clay Boswell 1893 4 T LNC1 0.28 0.3 SUB 22 MT ( cont.) Table 4: Pulverized Coal, 0.26 0.30 lb NOx/ mmBtu Units  Fuel Information Sorted Based on 2000 NOx Rate ( cont.)

Texas Harrington Station 6193 061B T OFA 0.28 0.3 SUB 19 WY Nevada Reid Gardner 2324 4 DB LNBO 0.28 0.31 BIT 20 UT Indiana Dean H Mitchell 996 5 T 0.29 NA SUB 19 WY Tennessee Gallatin 3403 1 T LNC2 0.29 NA BIT 10 IL Tennessee Gallatin 3403 2 T LNC2 0.29 NA BIT 10 IL Nebraska North Omaha 2291 1 T 0.29 NA SUB 19 WY Nebraska North Omaha 2291 2 T 0.29 NA SUB 19 WY Nebraska North Omaha 2291 3 T LNC1 0.29 NA SUB 19 WY Indiana Petersburg 994 1 T LNC3 0.29 NA BIT 11 IN Missouri Iatan 6065 1 DB LNB 0.29 0.26 SUB 19 WY Texas Welsh 6139 1 DB LNB 0.29 0.26 SUB 19 WY Wyoming Wyodak 6101 BW91 DB EIA_ LN 0.29 0.26 SUB 19 WY Louisiana Big Cajun 2 6055 2B3 DB LNB 0.29 0.28 SUB 19 WY Massachusetts Brayton Point 1619 2 T LNC3 0.29 0.28 BIT Virginia Clover 7213 1 T EIA_ LNAA 0.29 0.28 BIT 08 VA Minnesota Hoot Lake 1943 3 DB LNB 0.29 0.28 SUB 22 MT Texas Oklaunion 127 1 DB LNB 0.29 0.28 SUB 19 WY Nebraska Gerald Whelan Energy 60 1 T OFA 0.29 0.3 SUB 19 WY North Carolina Roxboro 2712 2 T LNC2, OFA 0.29 0.3 BIT 08 WV Mississippi Victor J Daniel Jr 6073 2 T 0.29 0.31 BIT 17 CO Pennsylvania Eddystone 3161 1 T LNC3 0.29 0.32 BIT 02 PA Colorado Rawhide 6761 101 T LNC1 0.29 0.33 SUB 19 WY Missouri Meramec 2104 2 T 0.29 0.44 SUB 19 WY Tennessee Gallatin 3403 3 T LNC2 0.3 NA BIT 10 IL Tennessee Gallatin 3403 4 T LNC2 0.3 NA BIT 10 IL Minnesota Sherburne County 6090 1 T LNC1 0.3 NA SUB 22 MT ( cont.)

Minnesota Sherburne County 6090 2 T LNC3 0.3 NA SUB 22 MT Kentucky Mill Creek 1364 1 T LN 0.3 0.26 BIT 09 KY Indiana Cayuga 1001 2 T LNC2 0.3 0.28 BIT 11 IN Texas Tolk Station 6194 172B T OFA 0.3 0.28 SUB 19 WY Massachusetts Brayton Point 1619 1 T LNC3 0.3 0.29 BIT Virginia Clover 7213 2 T EIA_ LNAA 0.3 0.29 BIT 08 VA Texas Harrington Station 6193 062B T OFA 0.3 0.29 SUB 19 WY Texas Monticello 6147 2 T 0.3 0.29 LIG 15 TX North Dakota R M Heskett 2790 B2 OB 0.3 0.29 LIG 21 ND Texas Monticello 6147 1 T 0.3 0.3 LIG 15 TX Texas Tolk Station 6194 171B T OFA 0.3 0.3 SUB 19 WY Missouri Montrose 2080 1 T O 0.3 0.31 SUB 19 WY Wisconsin Port Washington 4040 4 DB 0.3 0.31 BIT 02 PA Michigan J C Weadock 1720 7 T 0.3 0.32 SUB 19 WY Missouri Meramec 2104 4 DB LNB 0.3 0.33 SUB 19 WY Pennsylvania Portland 3113 2 T LNC3 0.3 0.34 BIT Table 5: Pulverized Coal, 0.26 0.30 lb NOx/ mmBtu Units  Average NOx Emission Rates 1995  2001Q3 Sorted Based on 2000 NOx Rate State Plant Name ORIS Unit ID Boiler Type Primary NOx Controls 1995 NOX Rate lb/ mmBtu 1996 NOX Rate lb/ mmBtu 1997 NOX Rate lb/ mmBtu 1998 NOX Rate lb/ mmBtu 1999 NOX Rate lb/ mmBtu 2000 NOX Rate lb/ mmBtu 2001 Thru Q3 Prelim.

NOX Rate lb/ mmBtu 2000_ 1995 Percent Reduction Indiana Dean H Mitchell 996 11 DB 0.60 0.39 0.30 0.32 0.29 0.26 NA 57 Indiana Dean H Mitchell 996 6 T EIA_ LNOV 0.60 0.39 0.32 0.33 0.29 0.26 NA 57 Texas J T Deely 6181 1 T LNC1 0.40 0.37 0.36 0.30 0.29 0.26 NA 35 Texas J T Deely 6181 2 T LNC1 0.40 0.37 0.35 0.32 0.29 0.26 NA 35 Michigan Belle River 6034 2 DB LNB 0.27 0.28 0.30 0.29 0.27 0.26 0.26 4 Colorado Arapahoe 465 4 DVF LNBO 0.38 0.35 0.31 0.24 0.22 0.26 0.27 32 Arkansas Independence 6641 2 T OFA 0.27 0.29 0.26 0.24 0.29 0.26 0.29 5 Alabama James H Miller Jr 6002 2 DB 0.53 0.58 0.57 0.54 0.31 0.26 0.29 51 Colorado Valmont 477 5 T LNC3 0.52 0.32 0.28 0.31 0.26 0.26 0.29 50 Illinois Waukegan 883 7 T LNC1 0.31 0.35 0.34 0.28 0.31 0.26 0.3 16 Michigan Dan E Karn 1702 2 DB LNBO 0.72 0.74 0.71 0.69 0.30 0.26 0.32 64 Michigan Belle River 6034 1 DB LNB 0.27 0.27 0.28 0.27 0.25 0.27 0.26 1 Michigan J R Whiting 1723 1 DB LNB 0.80 0.71 0.38 0.38 0.31 0.27 0.26 66 Iowa Muscatine 1167 9 T LN 0.34 0.32 0.31 0.29 0.30 0.27 0.26 19 Kansas Quindaro 1295 2 DB EIA_ LN 0.37 0.31 0.34 0.33 0.38 0.27 0.26 27 Wyoming Laramie River 6204 2 DB LNB 0.33 0.28 0.22 0.26 0.26 0.27 0.27 18 Kansas Holcomb 108 SGU1 DB LNB 0.25 0.28 0.28 0.29 0.28 0.27 0.28 _ 9 Georgia Scherer 6257 4 T EIA_ OV 0.29 0.31 0.32 0.34 0.27 0.27 0.28 8 Pennsylvania Eddystone 3161 2 T LNC3 0.38 0.31 0.30 0.31 0.24 0.27 0.29 29 Oklahoma GRDA 165 2 DB EIA_ LN 0.32 0.32 0.35 0.29 0.34 0.27 0.32 17 Georgia Yates 728 Y7BR T LNC2 0.31 0.31 0.31 0.32 0.29 0.28 0.26 11 Georgia Yates 728 Y6BR T LNC2 0.32 0.33 0.33 0.33 0.29 0.28 0.27 13 Arizona Cholla 113 4 T EIA_ OV 0.38 0.35 0.30 0.27 0.31 0.28 0.28 27 Arkansas Flint Creek 6138 1 DB LNB 0.38 0.30 0.30 0.31 0.30 0.28 0.29 26 Iowa Louisa 6664 101 DB EIA_ LN 0.26 0.30 0.27 0.26 0.26 0.28 0.29 _ 6 Minnesota Clay Boswell 1893 4 T LNC1 0.36 0.34 0.34 0.34 0.32 0.28 0.3 22 Texas Harrington Station 6193 061B T OFA 0.31 0.28 0.24 0.36 0.31 0.28 0.3 9 ( cont.) Table 5: Pulverized Coal, 0.26 0.30 lb NOx/ mmBtu Units  Average NOx Emission Rates 1995  2001Q3 Sorted Based on 2000 NOx Rate ( cont.)

Nevada Reid Gardner 2324 4 DB LNBO 0.32 0.26 0.27 0.28 0.30 0.28 0.31 13 Indiana Dean H Mitchell 996 5 T 0.44 0.39 0.35 0.35 0.29 0.29 NA 34 Tennessee Gallatin 3403 1 T LNC2 0.38 0.39 0.39 0.36 0.33 0.29 NA 23 Tennessee Gallatin 3403 2 T LNC2 0.38 0.39 0.39 0.36 0.33 0.29 NA 23 Nebraska North Omaha 2291 1 T 0.46 0.47 0.43 0.35 0.34 0.29 NA 37 Nebraska North Omaha 2291 2 T 0.46 0.48 0.43 0.35 0.34 0.29 NA 37 Nebraska North Omaha 2291 3 T LNC1 0.46 0.48 0.44 0.34 0.34 0.29 NA 37 Indiana Petersburg 994 1 T LNC3 0.44 0.28 0.26 0.30 0.26 0.29 NA 33 Missouri Iatan 6065 1 DB LNB 0.34 0.29 0.29 0.30 0.28 0.29 0.26 16 Texas Welsh 6139 1 DB LNB 0.23 0.25 0.26 0.33 0.32 0.29 0.26 _ 27 Wyoming Wyodak 6101 BW91 DB EIA_ LN 0.33 0.32 0.31 0.31 0.29 0.29 0.26 12 Louisiana Big Cajun 2 6055 2B3 DB LNB 0.25 0.30 0.28 0.26 0.29 0.29 0.28 _ 14 Massachusetts Brayton Point 1619 2 T LNC3 0.35 0.32 0.33 0.34 0.29 0.29 0.28 18 Virginia Clover 7213 1 T EIA_ LNAA 0.44 0.30 0.30 0.29 0.29 0.29 0.28 35 Minnesota Hoot Lake 1943 3 DB LNB 0.63 0.64 0.60 0.35 0.26 0.29 0.28 54 Texas Oklaunion 127 1 DB LNB 0.46 0.48 0.48 0.46 0.33 0.29 0.28 36 Nebraska Gerald Whelan Energy 60 1 T OFA 0.36 0.36 0.26 0.24 0.29 0.29 0.3 20 North Carolina Roxboro 2712 2 T LNC2, OFA 0.62 0.66 0.39 0.34 0.31 0.29 0.3 53 Mississippi Victor J Daniel Jr 6073 2 T 0.31 0.32 0.26 0.21 0.27 0.29 0.31 7 Pennsylvania Eddystone 3161 1 T LNC3 0.33 0.31 0.31 0.32 0.28 0.29 0.32 13 Colorado Rawhide 6761 101 T LNC1 0.34 0.33 0.32 0.35 0.35 0.29 0.33 15 Missouri Meramec 2104 2 T 0.53 0.65 0.53 0.47 0.38 0.29 0.44 45 Tennessee Gallatin 3403 3 T LNC2 0.42 0.40 0.39 0.37 0.35 0.3 NA 28 Tennessee Gallatin 3403 4 T LNC2 0.42 0.40 0.39 0.37 0.35 0.3 NA 28 Minnesota Sherburne County 6090 1 T LNC1 0.28 0.25 0.27 0.28 0.27 0.3 NA _ 7 ( cont.) Minnesota Sherburne County 6090 2 T LNC3 0.28 0.25 0.27 0.27 0.27 0.3 NA _ 7 Kentucky Mill Creek 1364 1 T LN 0.70 0.53 0.42 0.45 0.39 0.3 0.26 57 Indiana Cayuga 1001 2 T LNC2 0.33 0.36 0.34 0.33 0.33 0.3 0.28 10 Texas Tolk Station 6194 172B T OFA 0.37 0.33 0.30 0.29 0.32 0.3 0.28 20 Massachusetts Brayton Point 1619 1 T LNC3 0.36 0.30 0.31 0.32 0.29 0.3 0.29 18 Virginia Clover 7213 2 T EIA_ LNAA 0.00 0.00 0.00 0.00 0.28 0.3 0.29 Texas Harrington Station 6193 062B T OFA 0.40 0.33 0.29 0.29 0.34 0.3 0.29 24 Texas Monticello 6147 2 T 0.31 0.32 0.31 0.32 0.29 0.3 0.29 3 North Dakota R M Heskett 2790 B2 OB 0.34 0.35 0.32 0.34 0.31 0.3 0.29 13 Texas Monticello 6147 1 T 0.30 0.30 0.31 0.29 0.30 0.3 0.3 1 Texas Tolk Station 6194 171B T OFA 0.40 0.36 0.32 0.33 0.30 0.3 0.3 25 Missouri Montrose 2080 1 T O 0.43 0.36 0.32 0.35 0.33 0.3 0.31 31 Wisconsin Port Washington 4040 4 DB 0.30 0.29 0.30 0.30 0.28 0.3 0.31 0 Michigan J C Weadock 1720 7 T 0.41 0.41 0.41 0.36 0.35 0.3 0.32 26 Missouri Meramec 2104 4 DB LNB 0.94 0.37 0.34 0.34 0.33 0.3 0.33 68 Pennsylvania Portland 3113 2 T LNC3 0.43 0.48 0.41 0.34 0.28 0.3 0.34 30 ( cont.)

NOx Control Codes:

Code Description EIA LN EIA767 Data  Low NOx Burner Technology EIA LNAA EIA767 Data  Low NOx Burner Technology with Advanced Overfire Air EIA LNOV EIA767 Data  Low NOx Burner Technology with Overfire Air EIA OV EIA767 Data   Overfire Air LNB Low NOx Burner Technology ( DB Boilers)

LNBO Low NOx Burner Technology with Overfire Air ( DB Boilers)

LNC1 Low NOx Burner Technology with Close Coupled Overfire Air ( T Boilers)

LNC2 Low NOx Burner Technology with Separated Overfire Air ( T Boilers)

LNC3 Low NOx Burner Technology with Close Coupled and Separated Overfire Air ( T Boilers)

OFA Overfire Air U Uncontrolled


[Federal Register Volume 81, Number 88 (Friday, May 6, 2016)]
[Notices]
[Pages 27432-27433]
[FR Doc No: 2016-10664]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Project No. 2771-012]

The City of Holyoke Gas & Electric Department; Notice of Intent
To File License Application, Filing of Pre-Application Document, and
Approving Use of the Traditional Licensing Process

    a. Type of Filing: Notice of Intent to File License Application and
Request to Use the Traditional Licensing Process.
    b. Project No.: 2771-012.
    c. Date Filed: February 29, 2016.
    d. Submitted By: City of Holyoke Gas & Electric Department.
    e. Name of Project: Nonotuck Mill Hydroelectric Project.
    f. Location: Between the first and second level canals on the
Holyoke Canal System adjacent to the Connecticut River, in the city of
Holyoke in Hampden County, Massachusetts. The project does not occupy
federal land.
    g. Filed Pursuant to: 18 CFR 5.3 of the Commission's regulations.
    h. Potential Applicant Contact: Paul Ducheney, Superintendent,
Holyoke Gas & Electric, 99 Suffolk Street, Holyoke, MA 01040; (413)
536-9340<EMAIL_ADDRESS>    i. FERC Contact: Matt Buhyoff at<PHONE_NUMBER>; or email at
<EMAIL_ADDRESS>    j. Holyoke Gas and Electric filed its request to use the
Traditional Licensing Process on February 29, 2016. Holyoke Gas and
Electric provided public notice of its request on February 26, 2016. In
a letter dated April 29, 2016, the Director of the Division of
Hydropower Licensing approved Holyoke Gas and Electric's request to use
the Traditional Licensing Process.
    k. With this notice, we are initiating informal consultation with
the U.S. Fish and Wildlife Service and/or NOAA Fisheries under section
7 of the Endangered Species Act and the joint agency regulations
thereunder at 50 CFR, part 402; and NOAA Fisheries under section 305(b)
of the Magnuson-

Stevens Fishery Conservation and Management Act and implementing
regulations at 50 CFR 600.920. We are also initiating consultation with
the Massachusetts State Historic Preservation Officer, as required by
section 106, National Historical Preservation Act, and the implementing
regulations of the Advisory Council on Historic Preservation at 36 CFR
800.2.
    l. With this notice, we are designating Holyoke Gas and Electric as
the Commission's non-federal representative for carrying out informal
consultation pursuant to section 7 of the Endangered Species Act and
section 106 of the National Historic Preservation Act.
    m. Holyoke Gas & Electric filed a Pre-Application Document (PAD;
including a proposed process plan and schedule) with the Commission,
pursuant to 18 CFR 5.6 of the Commission's regulations.
    n. A copy of the PAD is available for review at the Commission in
the Public Reference Room or may be viewed on the Commission's Web site
(http://www.ferc.gov), using the ``eLibrary'' link. Enter the docket
number, excluding the last three digits in the docket number field to
access the document. For assistance, contact FERC Online Support at
<EMAIL_ADDRESS>(866) 208-3676 (toll free), or (202) 502-
8659 (TTY). A copy is also available for inspection and reproduction at
the address in paragraph h.
    o. The licensee states its unequivocal intent to submit an
application for a new license for Project No. 2771. Pursuant to 18 CFR
16.8, 16.9, and 16.10, each application for a new license and any
competing license applications must be filed with the Commission at
least 24 months prior to the expiration of the existing license. All
applications for license for this project must be filed by February 28,
2019.
    p. Register online at http://www.ferc.gov/docs-filing/esubscription.asp to be notified via email of new filing and issuances
related to this or other pending projects. For assistance, contact FERC
Online Support.

Kimberly D. Bose,
 Secretary.
[FR Doc. 2016-10664 Filed 5-5-16; 8:45 am]
 BILLING CODE 6717-01-P


its status as a tributary if it flows through a culvert, dam, or other
similar artificial break or through a debris pile, boulder field, or
similar natural break so long as the artificial or natural break
conveys perennial or intermittent flow to a tributary or other
jurisdictional water at the downstream end of the break. The alteration
or relocation of a tributary does not modify its status as a tributary
as long as it continues to satisfy the elements of this definition.
    (xii) Typical year. The term typical year means within the normal
range of precipitation over a rolling thirty-year period for a
particular geographic area.
    (xiii) Upland. The term upland means any land area that under
normal circumstances does not satisfy all three wetland delineation
criteria (i.e., hydrology, hydrophytic vegetation, hydric soils)
identified in paragraph (l)(3)(xv) of this section, and does not lie
below the ordinary high water mark or the high tide line of a water
identified in paragraph (l)(1)(i) through (vi) of this section. Waters
identified in paragraphs (l)(1)(i) through (vi) of this section are not
upland.
    (xiv) Waste treatment system. The term waste treatment system
includes all components, including lagoons and treatment ponds (such as
settling or cooling ponds), designed to convey or retain, concentrate,
settle, reduce, or remove pollutants, either actively or passively,
from wastewater prior to discharge (or eliminating any such discharge).

    (xv) Wetlands. The term wetlands means areas that are inundated or
saturated by surface or ground water at a frequency and duration
sufficient to support, and that under normal circumstances do support,
a prevalence of vegetation typically adapted for life in saturated soil
conditions. Wetlands generally include swamps, marshes, bogs, and
similar areas.
* * * * *
[FR Doc. 2019-00791 Filed 2-13-19; 8:45 am]
 BILLING CODE 6560-50-P


[Federal Register Volume 79, Number 194 (Tuesday, October 7, 2014)]
[Notices]
[Pages 60476-60477]
[FR Doc No: 2014-23845]

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DEPARTMENT OF HEALTH AND HUMAN SERVICES

Food and Drug Administration

[Docket No. FDA-2012-D-0432]

Pathological Complete Response in Neoadjuvant Treatment of High-
Risk Early-Stage Breast Cancer: Use as an Endpoint To Support
Accelerated Approval; Guidance for Industry; Availability

AGENCY: Food and Drug Administration, HHS.

ACTION: Notice.

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

SUMMARY: The Food and Drug Administration (FDA) is announcing the
availability of a guidance for industry entitled ``Pathological
Complete Response in Neoadjuvant Treatment of High-Risk Early-Stage
Breast Cancer: Use as an Endpoint to Support Accelerated Approval.''
This guidance is intended to assist applicants in designing trials to
support marketing approval of drugs to treat breast cancer in the
neoadjuvant (preoperative) setting using pathological complete response
(pCR) as a surrogate endpoint that could support approval under the
accelerated approval regulations. Despite advances in systemic therapy
of early-stage breast cancer over the past few decades, there remains a
significant unmet medical need for certain high-risk or poor prognosis
populations of early-stage breast cancer patients. This guidance is
intended to encourage industry innovation and expedite the development
of breakthrough therapies to treat high-risk early-stage breast cancer.
This guidance finalizes the draft guidance issued May 30, 2012.

DATES: Submit either electronic or written comments on Agency guidances
at any time.

ADDRESSES: Submit written requests for single copies of this guidance
to the Division of Drug Information, Center for Drug Evaluation and
Research, Food and Drug Administration, 10001 New Hampshire Ave.,
Hillandale Building, 4th Floor, Silver Spring, MD 20993-0002. Send one
self-addressed adhesive label to assist that office in processing your
requests. See the SUPPLEMENTARY INFORMATION section for electronic
access to the guidance document.
    Submit electronic comments on the guidance to http://www.regulations.gov. Submit written comments to the Division of Dockets
Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane,
Rm. 1061, Rockville, MD 20852.

FOR FURTHER INFORMATION CONTACT: Tatiana Prowell, Center for Drug
Evaluation and Research, Food and Drug Administration, 10903 New
Hampshire Ave., Bldg. 22, Rm. 2112, Silver Spring, MD 20993-0002, 301-
796-2330.

SUPPLEMENTARY INFORMATION:

I. Background

    FDA is announcing the availability of a guidance for industry
entitled ``Pathological Complete Response in Neoadjuvant Treatment of
High-Risk Early-Stage Breast Cancer: Use as an Endpoint to Support
Accelerated Approval.'' Under the accelerated approval regulations (21
CFR part 314, subpart H, and 21 CFR part 601, subpart E), FDA may grant
marketing approval for a new drug on the basis of adequate and well-
controlled trials establishing

that the drug has an effect on a surrogate endpoint that is reasonably
likely to predict clinical benefit (e.g., in early-stage breast cancer,
an improvement in disease-free or overall survival), provided that the
applicant conducts additional trials or collects additional data after
approval to verify and describe the predicted clinical benefit. This
guidance is intended to assist applicants in designing trials to
support marketing approval of drugs to treat breast cancer in the
neoadjuvant (preoperative) setting using pCR as a surrogate endpoint
that could support approval under the accelerated approval regulations.
The guidance provides acceptable definitions of pCR for regulatory
purposes. The guidance also describes appropriate patient populations
for inclusion in neoadjuvant trials conducted with regulatory intent.
Finally, the guidance outlines critical design features of trials for
both accelerated approval and confirmation of clinical benefit to
support regular approval.
    FDA recognizes that despite advances in adjuvant systemic therapy
of breast cancer over the past few decades, there remains a significant
unmet medical need for certain high-risk or poor prognosis populations
of early-stage breast cancer patients. Developing highly effective new
drugs for these populations is an FDA priority. In providing guidance
on the use of pCR as a surrogate endpoint that could support
accelerated approval in the neoadjuvant setting, FDA hopes to encourage
industry innovation and expedite the development and widespread
availability of highly effective novel therapies to treat high-risk
early-stage breast cancer.
    This guidance finalizes the draft guidance issued May 30, 2012 (77
FR 31858). The current version clarifies appropriate trial designs and
development strategies to support accelerated approval in the
neoadjuvant setting, defines acceptable endpoints for accelerated
approval and confirmation of clinical benefit, standardizes the
approach to postoperative systemic therapy, includes guidelines for
evaluation of the axillary lymph nodes, and provides detailed
recommendations for pathology standard operating procedures.
    This guidance is being issued consistent with FDA's good guidance
practices regulation (21 CFR 10.115). The guidance represents the
Agency's current thinking on use of pCR as an endpoint to support
accelerated approval of drug and biological products to treat high-risk
early-stage breast cancer patient populations. It does not create or
confer any rights for or on any person and does not operate to bind FDA
or the public. An alternative approach may be used if such approach
satisfies the requirements of the applicable statutes and regulations.

II. The Paperwork Reduction Act of 1995

    This guidance refers to previously approved collections of
information that are subject to review by the Office of Management and
Budget (OMB) under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-
3520). The collections of information in 21 CFR parts 312 and 314 have
been approved under OMB control numbers 0910-0014 and 0910-0001,
respectively. The collections of information for special protocol
assessments have been approved under OMB control number 0910-0470.

III. Comments

    Interested persons may submit either electronic comments regarding
this document to http://www.regulations.gov or written comments to the
Division of Dockets Management (see ADDRESSES). It is only necessary to
send one set of comments. Identify comments with the docket number
found in brackets in the heading of this document. Received comments
may be seen in the Division of Dockets Management between 9 a.m. and 4
p.m., Monday through Friday, and will be posted to the docket at http://www.regulations.gov.

IV. Electronic Access

    Persons with access to the Internet may obtain the document at
either http://www.fda.gov/Drugs/GuidanceComplianceRegulatoryInformation/Guidances/default.htm or http://www.regulations.gov.

    Dated: October 1, 2014.
Leslie Kux,
Assistant Commissioner for Policy.
[FR Doc. 2014-23845 Filed 10-6-14; 8:45 am]
BILLING CODE 4164-01-P


[Federal Register: February 13, 2008 (Volume 73, Number 30)]
[Proposed Rules]
[Page 8250-8251]
[DOCID:fr13fe08-25]

=======================================================================
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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R05-OAR-2007-1043; FRL-8528-5]

Approval and Promulgation of Air Quality Implementation Plans;
Michigan; PSD Regulations

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule; reopening of public comment period.

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

SUMMARY: EPA is reopening the public comment period for a proposed rule
published January 9, 2008 (73 FR 1570). On January 9, 2008, EPA
proposed a conditional approval of a revision to Michigan's SIP
submitted by the Michigan Department of Environmental Quality on
December 21, 2006. The revisions were submitted to add the Prevention
of Significant Deterioration

(PSD) construction permitting program. This program affects major
stationary sources in Michigan that are subject to or potentially
subject to the PSD construction permit program. On January 25, 2008,
EPA received a request from the Environmental Law and Policy Center,
the Michigan Energy Alternatives, the Michigan Land Use Institute, the
Natural Resources Defense Council and the Sierra Club, to extend the
public comment period an additional 30 days from the closing date of
February 8, 2008. EPA is granting this request by reopening the comment
period for an additional 30 days after February 8, 2008.

DATES: The comment period is extended until March 10, 2008.

ADDRESSES: Submit comments, identified by Docket ID No. EPA-R05-OAR-
2007-1043 to: Pamela Blakley, Chief, Air Permits Section, Air Programs
Branch (AR-18J), U.S. Environmental Protection Agency, 77 West Jackson
Boulevard, Chicago, Illinois 60604,<PHONE_NUMBER>,
<EMAIL_ADDRESS>Additional instructions to comment can be found

in the notice of proposed rulemaking published January 9, 2008 (73 FR
1570).

FOR FURTHER INFORMATION CONTACT: Laura Cossa, Environmental Engineer,
Air Permits Section, Air Programs Branch (AR-18J), U.S. Environmental
Protection Agency, Region 5, 77 West Jackson Boulevard, Chicago,
Illinois 60604,<PHONE_NUMBER><EMAIL_ADDRESS>
    Dated: February 6, 2008.
Gary Gulezian,
Acting Regional Administrator, Region 5.
[FR Doc. E8-2704 Filed 2-12-08; 8:45 am]

BILLING CODE 6560-50-P