CFR / Title 40 / Part 76 / Sec. 76.15 Test methods and procedures.

(a) The owner or operator may use the following tests as a basis for the report required by Sec. 76.10(e)(7):

(1) Conduct an ultimate analysis of coal using ASTM D 3176-89 (incorporated by reference as specified in Sec. 76.4);

(2) Conduct a proximate analysis of coal using ASTM D 3172-89 (incorporated by reference as specified in Sec. 76.4); and

(3) Measure the coal mass flow rate to each individual burner using ASME Power Test Code 4.2 (1991), ``Test Code for Coal Pulverizers'' or ISO 9931 (1991), ``Coal--Sampling of Pulverized Coal Conveyed by Gases in Direct Fired Coal Systems'' (incorporated by reference as specified in Sec. 76.4).

(b) The owner or operator may measure and record the actual NOX emission rate in accordance with the requirements of this part while varying the following parameters where possible to determine their effects on the emissions of NOX from the affected boiler:

(1) Excess air levels;

(2) Settings of burners or coal and air nozzles, including tilt and yaw, or swirl;

(3) For tangentially fired boilers, distribution of combustion air within the NOX emission control system;

(4) Coal mass flow rates to each individual burner;

(5) Coal-to-primary air ratio (based on pound per hour) for each burner, the average coal-to-primary air ratio for all burners, and the deviations of individual burners' coal-to-primary air ratios from the average value; and

(6) If the boiler uses varying types of coal, the type of coal. Provide the results of proximate and ultimate analyses of each type of as-fired coal.

(c) In performing the tests specified in paragraph (a) of this section, the owner or operator shall begin the tests using the equipment settings for which the NOX emission control system was designed to meet the NOX emission rate guaranteed by the primary NOX emission control system vendor. These results constitute the ``baseline controlled'' condition.

(d) After establishing the baseline controlled condition under paragraph (c) of this section, the owner or operator may:

(1) Change excess air levels 5 percent from the baseline controlled condition to determine the effects on emissions of NOX, by providing a minimum of three readings (e.g., with a baseline reading of 20 percent excess air, excess air levels will be changed to 19 percent and 21 percent);

(2) For tangentially fired boilers, change the distribution of combustion air within the NOX emission control system to determine the effects on NOX emissions by providing a minimum of three readings, one with the minimum, one with the baseline, and one with the maximum amounts of staged combustion air; and

(3) Show that the combustion process within the boiler is optimized (e.g., that the burners are balanced).

Sec. Appendix A to Part 76--Phase I Affected Coal-Fired Utility Units

With Group 1 or Cell Burner Boilers

Table 1--Phase I Tangentially Fired Units----------------------------------------------------------------------------------------------------------------

State Plant Unit Operator----------------------------------------------------------------------------------------------------------------ALABAMA...................... EC GASTON.................... 5 ALABAMA POWER CO.GEORGIA...................... BOWEN........................ 1BLR GEORGIA POWER CO.GEORGIA...................... BOWEN........................ 2BLR GEORGIA POWER CO.GEORGIA...................... BOWEN........................ 3BLR GEORGIA POWER CO.GEORGIA...................... BOWEN........................ 4BLR GEORGIA POWER CO.GEORGIA...................... JACK MCDONOUGH............... MB1 GEORGIA POWER CO.GEORGIA...................... JACK MCDONOUGH............... MB2 GEORGIA POWER CO.GEORGIA...................... WANSLEY...................... 1 GEORGIA POWER CO.GEORGIA...................... WANSLEY...................... 2 GEORGIA POWER CO.GEORGIA...................... YATES........................ Y1BR GEORGIA POWER CO.GEORGIA...................... YATES........................ Y2BR GEORGIA POWER CO.GEORGIA...................... YATES........................ Y3BR GEORGIA POWER CO.GEORGIA...................... YATES........................ Y4BR GEORGIA POWER CO.GEORGIA...................... YATES........................ Y5BR GEORGIA POWER CO.GEORGIA...................... YATES........................ Y6BR GEORGIA POWER CO.GEORGIA...................... YATES........................ Y7BR GEORGIA POWER CO.ILLINOIS..................... BALDWIN...................... 3 ILLINOIS POWER CO.ILLINOIS..................... HENNEPIN..................... 2 ILLINOIS POWER CO.ILLINOIS..................... JOPPA........................ 1 ELECTRIC ENERGY INC.ILLINOIS..................... JOPPA........................ 2 ELECTRIC ENERGY INC.ILLINOIS..................... JOPPA........................ 3 ELECTRIC ENERGY INC.ILLINOIS..................... JOPPA........................ 4 ELECTRIC ENERGY INC.ILLINOIS..................... JOPPA........................ 5 ELECTRIC ENERGY INC.ILLINOIS..................... JOPPA........................ 6 ELECTRIC ENERGY INC.ILLINOIS..................... MEREDOSIA.................... 5 CEN ILLINOIS PUB SER.ILLINOIS..................... VERMILION.................... 2 ILLINOIS POWER CO.INDIANA...................... CAYUGA....................... 1 PSI ENERGY INC.INDIANA...................... CAYUGA....................... 2 PSI ENERGY INC.INDIANA...................... EW STOUT..................... 50 INDIANAPOLIS PWR & LT.INDIANA...................... EW STOUT..................... 60 INDIANAPOLIS PWR & LT.INDIANA...................... EW STOUT..................... 70 INDIANAPOLIS PRW & LT.INDIANA...................... HT PRITCHARD................. 6 INDIANAPOLIS PWR & LT.INDIANA...................... PETERSBURG................... 1 INDIANAPOLIS PWR & LT.INDIANA...................... PETERSBURG................... 2 INDIANAPOLIS PWR & LT.INDIANA...................... WABASH RIVER................. 6 PSI ENERGY INC.IOWA......................... BURLINGTON................... 1 IOWA SOUTHERN UTL.IOWA......................... ML KAPP...................... 2 INTERSTATE POWER CO.IOWA......................... RIVERSIDE.................... 9 IOWA-ILL GAS & ELEC.KENTUCKY..................... ELMER SMITH.................. 2 OWENSBORO MUN UTIL.KENTUCKY..................... EW BROWN..................... 2 KENTUCKY UTL CO.KENTUCKY..................... EW BROWN..................... 3 KENTUCKY UTL CO.KENTUCKY..................... GHENT........................ 1 KENTUCKY UTL CO.MARYLAND..................... MORGANTOWN................... 1 POTOMAC ELEC PWR CO.MARYLAND..................... MORGANTOWN................... 2 POTOMAC ELEC PWR CO.MICHIGAN..................... JH CAMPBELL.................. 1 CONSUMERS POWER CO.MISSOURI..................... LABADIE...................... 1 UNION ELECTRIC CO.MISSOURI..................... LABADIE...................... 2 UNION ELECTRIC CO.MISSOURI..................... LABADIE...................... 3 UNION ELECTRIC CO.MISSOURI..................... LABADIE...................... 4 UNION ELECTRIC CO.MISSOURI..................... MONTROSE..................... 1 KANSAS CITY PWR & LT.MISSOURI..................... MONTROSE..................... 2 KANSAS CITY PWR & LT.MISSOURI..................... MONTROSE..................... 3 KANSAS CITY PWR & LT.NEW YORK..................... DUNKIRK...................... 3 NIAGARA MOHAWK PWR.NEW YORK..................... DUNKIRK...................... 4 NIAGARA MOHAWK PWR.NEW YORK..................... GREENIDGE.................... 6 NY STATE ELEC & GAS.NEW YORK..................... MILLIKEN..................... 1 NY STATE ELEC & GAS.NEW YORK..................... MILLIKEN..................... 2 NY STATE ELEC & GAS.OHIO......................... ASHTABULA.................... 7 CLEVELAND ELEC ILLUM.OHIO......................... AVON LAKE.................... 11 CLEVELAND ELEC ILLUM.OHIO......................... CONESVILLE................... 4 COLUMBUS STHERN PWR.OHIO......................... EASTLAKE..................... 1 CLEVELAND ELEC ILLUM.OHIO......................... EASTLAKE..................... 2 CLEVELAND ELEC ILLUM.OHIO......................... EASTLAKE..................... 3 CLEVELAND ELEC ILLUM.OHIO......................... EASTLAKE..................... 4 CLEVELAND ELEC ILLUM.OHIO......................... MIAMI FORT................... 6 CINCINNATI GAS & ELEC.OHIO......................... WC BECKJORD.................. 5 CINCINNATI GAS & ELEC.OHIO......................... WC BECKJORD.................. 6 CINCINNATI GAS & ELEC.PENNSYLVANIA................. BRUNNER ISLAND............... 1 PENNSYLVANIA PWR & LT.PENNSYLVANIA................. BRUNNER ISLAND............... 2 PENNSYLVANIA PWR & LT.

PENNSYLVANIA................. BRUNNER ISLAND............... 3 PENNSYLVANIA PWR & LT.PENNSYLVANIA................. CHESWICK..................... 1 DUQUESNE LIGHT CO.PENNSYLVANIA................. CONEMAUGH.................... 1 PENNSYLVANIA ELEC CO.PENNSYLVANIA................. CONEMAUGH.................... 2 PENNSYLVANIA ELEC CO.PENNSYLVANIA................. PORTLAND..................... 1 METROPOLITAN EDISON.PENNSYLVANIA................. PORTLAND..................... 2 METROPOLITAN EDISON.PENNSYLVANIA................. SHAWVILLE.................... 3 PENNSYLVANIA ELEC CO.PENNSYLVANIA................. SHAWVILLE.................... 4 PENNSYLVANIA ELEC CO.TENNESSEE.................... GALLATIN..................... 1 TENNESSEE VAL AUTH.TENNESSEE.................... GALLATIN..................... 2 TENNESSEE VAL AUTH.TENNESSEE.................... GALLATIN..................... 3 TENNESSEE VAL AUTH.TENNESSEE.................... GALLATIN..................... 4 TENNESSEE VAL AUTH.TENNESSEE.................... JOHNSONVILLE................. 1 TENNESSEE VAL AUTH.TENNESSEE.................... JOHNSONVILLE................. 2 TENNESSEE VAL AUTH.TENNESSEE.................... JOHNSONVILLE................. 3 TENNESSEE VAL AUTH.TENNESSEE.................... JOHNSONVILLE................. 4 TENNESSEE VAL AUTH.TENNESSEE.................... JOHNSONVILLE................. 5 TENNESSEE VAL AUTH.TENNESSEE.................... JOHNSONVILLE................. 6 TENNESSEE VAL AUTH.WEST VIRGINIA................ ALBRIGHT..................... 3 MONONGAHELA POWER CO.WEST VIRGINIA................ FORT MARTIN.................. 1 MONONGAHELA POWER CO.WEST VIRGINIA................ MOUNT STORM.................. 1 VIRGINIA ELEC & PWR.WEST VIRGINIA................ MOUNT STORM.................. 2 VIRGINIA ELEC & PWR.WEST VIRGINIA................ MOUNT STORM.................. 3 VIRGINIA ELEC & PWR.WISCONSIN.................... GENOA........................ 1 DAIRYLAND POWER COOP.WISCONSIN.................... SOUTH OAK CREEK.............. 7 WISCONSIN ELEC POWER.WISCONSIN.................... SOUTH OAK CREEK.............. 8 WISCONSIN ELEC POWER.----------------------------------------------------------------------------------------------------------------

Table 2--Phase I Dry Bottom-Fired Units----------------------------------------------------------------------------------------------------------------

KENTUCKY...................... HMP&L; STATION 2............... H1 BIG RIVERS ELEC CORP.KENTUCKY...................... HMP&L; STATION 2............... H2 BIG RIVERS ELEC CORP.KENTUCKY...................... HL SPURLOCK................... 1 EAST KY PWR COOP.KENTUCKY...................... JS COOPER..................... 1 EAST KY PWR COOP.KENTUCKY...................... JS COOPER..................... 2 EAST KY PWR COOP.MARYLAND...................... CHALK POINT................... 1 POTOMAC ELEC PWR CO.MARYLAND...................... CHALK POINT................... 2 POTOMAC ELEC PWR CO.MINNESOTA..................... HIGH BRIDGE................... 6 NORTHERN STATES PWR.MISSISSIPPI................... JACK WATSON................... 4 MISSISSIPPI PWR CO.MISSISSIPPI................... JACK WATSON................... 5 MISSISSIPPI PWR CO.MISSOURI...................... JAMES RIVER................... 5 SPRINGFIELD UTL.OHIO.......................... CONESVILLE.................... 3 COLUMBUS STHERN PWR.OHIO.......................... EDGEWATER..................... 13 OHIO EDISON CO.OHIO.......................... MIAMI FORT \1\................ 5-1 CINCINNATI GAS&ELEC.;OHIO.......................... MIAMI FORT \1\................ 5-2 CINCINNATI GAS&ELEC.;OHIO.......................... PICWAY........................ 9 COLUMBUS STHERN PWR.OHIO.......................... RE BURGER..................... 7 OHIO EDISON CO.OHIO.......................... RE BURGER..................... 8 OHIO EDISON CO.OHIO.......................... WH SAMMIS..................... 5 OHIO EDISON CO.OHIO.......................... WH SAMMIS..................... 6 OHIO EDISON CO.PENNSYLVANIA.................. ARMSTRONG..................... 1 WEST PENN POWER CO.PENNSYLVANIA.................. ARMSTRONG..................... 2 WEST PENN POWER CO.PENNSYLVANIA.................. MARTINS CREEK................. 1 PENNSYLVANIA PWR & LT.PENNSYLVANIA.................. MARTINS CREEK................. 2 PENNSYLVANIA PWR & LT.PENNSYLVANIA.................. SHAWVILLE..................... 1 PENNSYLVANIA ELEC CO.PENNSYLVANIA.................. SHAWVILLE..................... 2 PENNSYLVANIA ELEC CO.PENNSYLVANIA.................. SUNBURY....................... 3 PENNSYLVANIA PWR & LT.PENNSYLVANIA.................. SUNBURY....................... 4 PENNSYLVANIA PWR & LT.TENNESSEE..................... JOHNSONVILLE.................. 7 TENNESSEE VAL AUTH.TENNESSEE..................... JOHNSONVILLE.................. 8 TENNESSEE VAL AUTH.TENNESSEE..................... JOHNSONVILLE.................. 9 TENNESSEE VAL AUTH.TENNESSEE..................... JOHNSONVILLE.................. 10 TENNESSEE VAL AUTH.WEST VIRGINIA................. HARRISON...................... 1 MONONGAHELA POWER CO.WEST VIRGINIA................. HARRISON...................... 2 MONONGAHELA POWER CO.WEST VIRGINIA................. HARRISON...................... 3 MONONGAHELA POWER CO.WEST VIRGINIA................. MITCHELL...................... 1 OHIO POWER CO.WEST VIRGINIA................. MITCHELL...................... 2 OHIO POWER CO.WISCONSIN..................... JP PULLIAM.................... 8 WISCONSIN PUB SER CO.WISCONSIN..................... NORTH OAK CREEK \2\........... 1 WISCONSIN ELEC PWR.WISCONSIN..................... NORTH OAK CREEK \2\........... 2 WISCONSIN ELEC PWR.WISCONSIN..................... NORTH OAK CREEK \2\........... 3 WISCONSIN ELEC PWR.WISCONSIN..................... NORTH OAK CREEK \2\........... 4 WISCONSIN ELEC PWR.WISCONSIN..................... SOUTH OAK CREEK \2\........... 5 WISCONSIN ELEC PWR.WISCONSIN..................... SOUTH OAK CREEK \2\........... 6 WISCONSIN ELEC PWR.----------------------------------------------------------------------------------------------------------------\1\ Vertically fired boiler.\2\ Arch-fired boiler.

Table 3--Phase I Cell Burner Technology Units----------------------------------------------------------------------------------------------------------------

State Plant Unit Operator----------------------------------------------------------------------------------------------------------------INDIANA....................... WARRICK....................... 4 STHERN IND GAS & EL.MICHIGAN...................... JH CAMPBELL................... 2 CONSUMERS POWER CO.OHIO.......................... AVON LAKE..................... 12 CLEVELAND ELEC ILLUM.OHIO.......................... CARDINAL...................... 1 CARDINAL OPERATING.OHIO.......................... CARDINAL...................... 2 CARDINAL OPERATING.OHIO.......................... EASTLAKE...................... 5 CLEVELAND ELEC ILLUM.OHIO.......................... GENRL JM GAVIN................ 1 OHIO POWER CO.OHIO.......................... GENRL JM GAVIN................ 2 OHIO POWER CO.OHIO.......................... MIAMI FORT.................... 7 CINCINNATI GAS & EL.OHIO.......................... MUSKINGUM RIVER............... 5 OHIO POWER CO.OHIO.......................... WH SAMMIS..................... 7 OHIO EDISON CO.PENNSYLVANIA.................. HATFIELDS FERRY............... 1 WEST PENN POWER CO.PENNSYLVANIA.................. HATFIELDS FERRY............... 2 WEST PENN POWER CO.PENNSYLVANIA.................. HATFIELDS FERRY............... 3 WEST PENN POWER CO.TENNESSEE..................... CUMBERLAND.................... 1 TENNESSEE VAL AUTH.TENNESSEE..................... CUMBERLAND.................... 2 TENNESSEE VAL AUTH.WEST VIRGINIA................. FORT MARTIN................... 2 MONONGAHELA POWER CO.---------------------------------------------------------------------------------------------------------------- Sec. Appendix B to Part 76--Procedures and Methods for Estimating Costs

of Nitrogen Oxides Controls Applied to Group 1, Boilers

1. Purpose and Applicability

This technical appendix specifies the procedures, methods, and data that the Administrator will use in establishing ``***the degree of reduction achievable through this retrofit application of the best system of continuous emission reduction, taking into account available technology, costs, and energy and environmental impacts; and which is comparable to the costs of nitrogen oxides controls set pursuant to subsection (b)(1) (of section 407 of the Act).'' In developing the allowable NOX emissions limitations for Group 2 boilers pursuant to subsection (b)(2) of section 407 of the Act, the Administrator will consider only those systems of continuous emission reduction that, when applied on a retrofit basis, are comparable in cost to the cost in constant dollars of low NOX burner technology applied to Group 1, Phase I boilers.

The Administrator will evaluate the capital cost (in dollars per kilowatt electrical ($/kW)), the operating and maintenance costs (in $/year), and the cost-effectiveness (in annualized $/ton NOX removed) of installed low NOX burner technology controls over a range of boiler sizes (as measured by the gross electrical capacity of the associated generator in megawatt electrical (MW)) and utilization rates (in percent gross nameplate capacity on an annual basis) to develop estimates of the capital costs and cost effectiveness for Group 1, Phase I boilers. The following units will be excluded from these determinations of the capital costs and cost effectiveness of NOX controls set pursuant to subsection (b)(1) of section 407 of the Act: (1) Units employing an alternative technology, or overfire air as applied to wall-fired boilers or separated overfire air as applied to tangentially fired boilers, in lieu of low NOX burner technology for reducing NOX emissions; (2) units employing no controls, only controls installed before November 15, 1990, or only modifications to boiler operating parameters (e.g., burners out of service or fuel switching) for reducing NOX emissions; and (3) units that have not achieved the applicable emission limitation. 2. Average Capital Cost for Low NOX Burner Technology Applied

to Group 1 Boilers

The Administrator will use the procedures, methods, and data specified in this section to estimate the average capital cost (in $/kW) of installed low NOX burner technology applied to Group 1 boilers.

2.1 Using cost data submitted pursuant to the reporting requirements in section 4 below, boiler-specific actual or estimated actual capital costs will be determined for each unit in the population specified in section 1 above for assessing the costs of installed low NOX burner technology. The scope of installed low NOX burner technology costs will include the following capital costs for retrofit application: (1) For the burner portion--burners or air and coal nozzles, burner throat and waterwall modifications, and windbox modifications; and, where applicable, (2) for the combustion air staging portion--waterwall modifications or panels, windbox modifications, and ductwork, and (3) scope adders or supplemental equipment such as replacement or additional fans, dampers, or ignitors necessary for the proper operation of the low NOX burner technology. Capital costs associated with boiler restoration or refurbishment such as replacement of air heaters, asbestos abatement, and recasing will not be included in the cost basis for installed low NOX burner technology. The scope of installed low NOX burner technology retrofit capital costs will include materials, construction and installation labor, engineering, and overhead costs.

2.2 Using gross nameplate capacity (in MW) for each unit as reported in the National Allowance Data Base (NADB), boiler-specific capital costs will be converted to a $/kW basis.

2.3 Capital cost curves ($/kW versus boiler size in MW) or equations for installed low NOX burner technology retrofit costs will be developed for: (1) Dry bottom wall fired boilers (excluding units applying cell burner technology) and (2) tangentially fired boilers.

3. [Reserved]

4. Reporting Requirements

4.1 The following information is to be submitted by each designated representative of a Phase I affected unit subject to the reporting requirements of Sec. 76.14(c):

4.1.1 Schedule and dates for baseline testing, installation, and performance testing of low NOX burner technology.

4.1.2 Estimates of the annual average baseline NOX emission rate, as specified in section 3.1.1, and the annual average controlled NOX emission rate, as specified in section 3.1.2, including the supporting continuous emission monitoring or other test data.

4.1.3 Copies of pre-retrofit and post-retrofit performance test reports.

4.1.4 Detailed estimates of the capital costs based on actual contract bids for each component of the installed low NOX burner technology including the items listed in section 2.1. Indicate number of bids solicited. Provide a copy of the actual agreement for the installed technology.

4.1.5 Detailed estimates of the capital costs of system replacements or upgrades such as coal pipe changes, fan replacements/upgrades, or mill replacements/upgrades undertaken as part of the low NOX burner technology retrofit project.

4.1.6 Detailed breakdown of the actual costs of the completed low NOX burner technology retrofit project where low NOX burner technology costs (section 4.1.4) are disaggregated, if feasible, from system replacement or upgrade costs (section 4.1.5).

4.1.7 Description of the probable causes for significant differences between actual and estimated low NOX burner technology retrofit project costs.

4.1.8 Detailed breakdown of the burner and, if applicable, combustion air staging system annual operating and maintenance costs for the items listed in section 3.3 before and after the installation, shakedown, and/or optimization of the installed low NOX burner technology. Include estimates and a description of the probable causes of the incremental annual operating and maintenance costs (or savings) attributable to the installed low NOX burner technology.

4.2 All capital cost estimates are to be broken down into materials costs, construction and installation labor costs, and engineering and overhead costs. All operating and maintenance costs are to be broken down into maintenance materials costs, maintenance labor costs, operating labor costs, and fan electricity costs. All capital and operating costs are to be reported in dollars with the year of expenditure or estimate specified for each component. [60 FR 18761, Apr. 13, 1995, as amended at 61 FR 67164, Dec. 19, 1996; 62 FR 3464, Jan. 23, 1997]