0 Confidential/Trade Secret

EXHIBIT 6 PSC REF#:96106

Part 12 of 13 Public Service Commission of Wisconsin 6680-CE-170 Exhibit _____ (RDB-1) Schedule 3

9/19/2008 (aff) Response of RECEIVED: 06/16/08, 1:15:42 PM Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 1-18 Revised

Docket Number: 6680-CE-170 Date of Request: March 9, 2007 Information Requested By: Christine Swailes Date Responded: March 20, 2007 May 3, 2007 Revised Author: Steve Jackson Author’s Title: Senior Environmental Specialist Author’s Telephone No.: (608) 458-5704 Witness: (If other than Author)

Data Request No. 1-18:

Provide annual estimates of CO emissions for 300, 400, and 500 MW CFB, pulverized 2 coal (PC), and SCPC units.

Response:

Estimated annual CO2 emissions in tons for 300, 400, and 500 MW CFB and PC (subcritical) units are presented in the following table:

Unit Type 300 MW 400 MW 500 MW PC (sub-critical) 2,683,177 3,568,204 4,467,280 CFB 2, 594,450 3,279,058 4,319,042 * CFB assumes 80% PRB, 20% Pet Coke blend * Emissions based on 87% capacity * Emission factors used based on AP-42, section 1.1.

Page 1 of 1 Exhibit _____ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 1-83 Supplement

Docket Number: 6680-CE-170 Date of Request: March 9, 2007 Information Requested By: Christine Swailes Date Responded: April 10, 2007 May 3, 2007 Supplement Author: Kirby Letheby Author’s Title: Team Lead – New Generation Author’s Telephone No.: 608-458-3276 Witness: (If other than Author)

Data Request No. 1-83:

1.1.15.3, p. NED 49: What is the capacity in cubic yards of the proposed pile that will occupy 15 acres? What is the proposed maximum height of the coal pile? What is the capacity in cubic yards of the existing pile that occupies 12 acres? What is the height of the existing pile at this capacity? Provide plan and elevation 9 drawings indicating how the pile size will increase to 26 acres if barge unloading is to be utilized.

Response:

The capacity of the proposed 15-acre coal pile is approximately 651,000 cubic yards. This capacity is the volume of the 15 acres with a 35-foot tall pile and 3:1 side slopes. The actual volume of coal that can be stored may be less because of the separation of the coal and pet coke piles.

The proposed maximum height of the coal and pet coke piles is 35 feet.

The capacity of the existing 12-acre coal pile is approximately 412,000 cubic yards. This capacity is the volume of the 12 acres with a 35-foot tall pile and 3:1 side slopes. The actual volume of coal that can be stored may be less because of the separation of the coal and pet coke piles

The plan for the 26-acre coal pile size is shown in the attached Plant and Facilities Plan 26 Acre Coal Pile NED 3 Preferred Site, and a section view of the coal pile is shown in the attached drawing Coal/Pet Storage Pile Typical Section – NED 3 Preferred Site.

Supplemental Response:

This supplemental response provides the attachments that were inadvertently omitted from the response dated April 10, 2007.

Page 1 of 1 Exhibit _____ (RDB-1) Schedule 3

KEY INDEX

37 1 TURBINE GENERATOR

2 BOILER

3 DRY POLISHING SCRUBBER 27 4 BAG HOUSE 26 5 STACK

6 FLY ASH SILO

7 COOLING TOWER

8 CAR DUMPER

9 PROPERTY LINE

10 COAL CONVEYOR

11 150 DAY COAL/PET COKE PILE

12 NEW MOORING CELL

13 CRUSHER HOUSE

14 WATER TREATMENT

15 LIMESTONE UNLOADING

16 26 ACRE COVERED LIMESTONE STORAGE COAL PILE 17 TEMPORARY PLANT ACCESS ROAD 9 18 CONSTRUCTION PARKING

19 28 CONSTRUCTION OFFICE TRAILERS

20 BIOMASS HANDLING AREA

21 LIME SILO

22 COAL PILE RUNOFF POND

23 FUEL OIL STORAGE TANK

24 SORBENT INJECTION STORAGE SILO

25 SERVICE WATER TANK 22 8 26 LOADED UNIT TRAIN PARALLEL INDUSTRIAL TRACK

UNLOADED UNIT TRAIN PARALLEL INDUSTRIAL TRACK 30 30 27 28 TRACK SERVICE ROAD

17 29 DEMINERALIZED WATER TANK

30 COAL/PET COKE STACKOUT/RECLAIM 36 31 COLLECTOR WELL

32 STORMWATER DETENTION POND

33 EXISTING UNITS 11 34 EXISTING CRUSHER HOUSE 30 35 EXISTING SUBSTATION 13 36 EXISTING ASH/SLAG POND 30 37 RELOCATED BNSF MAIN LINE TRACK 10 18 38 BED ASH SILO 22 39 HYDRATED LIME SILO 20 40 AQUEOUS AMMONIA STORAGE

41 LIMESTONE PREPARATION BUILDING 38 12 6 42 OFF-SITE CONSTRUCTION PARKING 35 34 15 43 OFF-SITE LAYDOWN

33 41 40 19

2 25 1 42 29

5 3 31 4 14 39 32 7 SOURCE: AERIAL PHOTO - NAIP 2005 AERIAL IMAGERY 21 43

NORTH 24

MISSISSIPPI RIVER

500' 0' 500' Plant and Facilities Plan 26 Acre Coal Pile SCALE IN FEET NED 3 Preferred Site Wisconsin Power and Light Company

Exhibit _____ (RDB-1) Schedule 3

680 1290680

644'

660 660

EL 655

640 1290640

3 3 1 COAL/PETE STORAGE 1

620 620

EXISITNG GRADE

600 600

TYPICAL COAL/PETE STORAGE PILE SECTION

NOT TO SCALE

Coal/Pete Storage Pile Typical Section NED 3 Preferred Site Wisconsin Power and Light Company

Exhibit ____ (RDB-1) Schedule 3 Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 1-139 Revised

Docket Number: 6680-CE-170 Date of Request: March 9, 2007 Information Requested By: Christine Swailes Date Responded: March 21, 2007 May 3, 2007 Revised Author: Steve Jackson Author’s Title: Senior Environmental Specialist Author’s Telephone No.: 608-458-5704 Witness: (If other than Author)

Data Request No. 1-139:

1.2.17, p. NED 100 and COL 236: The application lacks detail on the control technology for mercury. How much sorbent injection will occur? To what level will mercury be controlled? Provide CO2 equivalents and discussion of other pollutant contributions to

greenhouse gases.

Response: Specific information for controlling mercury is included in the PSD construction permit applications. For COL 3, mercury will be controlled as a co-benefit of the reductions achieved by the proposed wet FGD and fabric filter. For NED 3, mercury will be controlled as a co-benefit of the reductions achieved by the proposed limestone injection, “polishing” advanced semi-dry FGD, and fabric filter. NED 3 design includes the installation of a sorbent injection system. An optimization study will be conducted for the control of mercury to evaluate the effects of fuel blending, boiler operation, “polishing” advanced semi-dry FGD, and fabric filter on mercury emissions, and determine the need to inject sorbent and at what rates.

CO2 equivalent (or CO2e) is the quantity of a given greenhouse gas (GHG) multiplied by its global warming potential (GWP). This is the standard unit for comparing emissions of different GHGs. GWPs are used to compare the abilities of different greenhouse gases to trap heat in the atmosphere. GWPs are based on the radiative efficiency (heat-absorbing ability) of each gas relative to that of CO2, as well as the decay rate of each gas (the amount removed from the atmosphere over a given number of years) relative to that of CO2.

The GWP provides a mechanism for converting emissions of various gases into a common measure. The table below provides the GWPs for the emissions of concern for the WPL new generation project as published in the Third Assessment Report of the Intergovernmental Panel on Climate Change (IPCC).

Page 1 of 2 Exhibit ____ (RDB-1) Schedule 3

Emission GWP (in tons of CO2 equivalent) CO2 1 CH4 23 N2O 296 Intergovernmental Panel on Climate Change, Climate Change 2001: Third Assessment Report

The following tables provide an estimate in CO2e of the projected greenhouse gas emissions related to the WPL baseload project.

NED3 Greenhouse Gas CO2e Estimate Greenhouse Gas Emission CO2e (tons/year) CO2 2,594,450 2,594,450 CH4 40.5 932 N2O 2,363 699,547 Total 3,294,929

COL3 Greenhouse Gas CO2e Estimate Greenhouse Gas Emission CO2e (tons/year) CO2 2,683,177 2,683,177 CH4 37.6 866 N2O 60.2 17,824 Total 2,701,867

Page 2 of 2 Exhibit ____ (RDB-1) Schedule 3 Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 1-145 Revised

Docket Number: 6680-CE-170 Date of Request: March 9, 2007 Information Requested By: Christine Swailes Date Responded: April 3, 2007 May 3, 2007 Revised Author: Steve Jackson Author’s Title: Senior Environmental Specialist Author’s Telephone No.: 605-458-5704 Witness: (If other than Author)

Data Request No. 1-145:

1.2.17.4, p. NED 107 and COL 236: List all potential process and input sources for CO2, N2O, and CH4 emissions from the proposed NED 3 and COL 3 plants, including those

associated with other plant inputs besides the coal, pet coke, and biomass fuels, such as limestone. Tabulate the expected resulting greenhouse gas emissions for each proposed plant site.

Response:

The sources for emissions of CO2, N2O, and CH4 include the fuel source and combustion equipment. The use of limestone in the NED 3 CFB boiler and in the COL 3 WFGD are likely to add CO2 emissions. The following tables list these sources for NED3 and COL3.

NED 3 CO2 TPY N2O TPY CH4 TPY CFB Boiler (Fuel Combustion) 2,594,450 2,363 41 Emergency Diesel Fire Pump 30 1.16E-5 6.60E-2 Diesel Auxiliary Boiler 9,151 4.51E-2 2.13E-2 Emergency Diesel Generator 129 5.70E-4 7.04E-3 Mobile Sources 23,817 0.7 1 Limestone Injection to CFB Boiler 32,161 0 0 * CFB assumes 80% PRB, 20% Pet Coke blend * CFB emissions and Limestone Injection based on 87% capacity * Limestone injection theoretical rate to remove 90% of sulfur in the CFB boiler * Emission factors used based on AP-42 * Mobile source emissions for heavy trucks and equipment from Transport Canada

Page 1 of 2 Exhibit ____ (RDB-1) Schedule 3

COL 3 CO2 TPY N2O TPY CH4 TPY PC Boiler (Fuel Combustion) 2,683,177 60 38 Emergency Diesel Fire Pump 30 1.16E-5 6.60E-2 Diesel Auxiliary Boiler 9,151 4.51E-2 2.13E-2 Emergency Diesel Generator 129 5.70E-4 7.04E-3 Mobile Sources 23,149 0.7 1 Limestone Injection to WFGD 7,558 0 0 * Assumes 100% PRB * Emissions and Limestone Injection based on 87% capacity * Emission factors used based on AP-42 * Mobile source emissions for heavy trucks and equipment from Transport Canada

Page 2 of 2 Exhibit ____ (RDB-1) Schedule 3 Revised Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Requests Nos. 1-139 and 1-145

Docket Number: 6680-CE-170 Date of Request: March 9, 2007 Information Requested By: Christine Swailes Date Responded: February 22, 2008 February 22, 2008 Revised Author of Update: Kevin Vesperman Author’s Title: General Manager-Strategic Resource Deployment Author’s Telephone No.: 608-458-3141 Witness: (If other than Author)

Data Request No. 1-139:

greenhouse gases.

Data Request No. 1-145:

1.2.17.4, p. NED 107 and COL 236: List all potential process and input sources for CO2, N2O, and CH4 emissions from the proposed NED 3 and COL 3 plants, including those

associated with other plant inputs besides the coal, pet coke, and biomass fuels, such as limestone. Tabulate the expected resulting greenhouse gas emissions for each proposed plant site.

Revised Responses:

This update is being provided to reflect the current detailed design of NED 3. Regarding Data Request No. 1-139, WPL’s prior response is being updated only with regard to the last sentence in the Data Request 1-139. This analysis of the emissions is based on the bid phase stage of the design, i.e. the design as it is being finalized for release for bid. The analysis of the emissions of CO2, N2O, and CH4 includes the inputs from the fuel source, the impact of the combustion process, and the pollution control equipment.

Based on heat balance modeling of the current design, NED 3 has a rated net output of 326 MW based at 59°F (60% Relative Humidity). For the purposes of the revised responses to the data requests, the rating of the COL 3 unit was set at a nominally equivalent net output rating at the same conditions.

Page 1 of 11

Exhibit ____ (RDB-1) Schedule 3

The emissions data is provided by fuel supply and includes:

For the NED 3 Unit- • 100% Wyoming Powder River Basin (PRB) coal, • 80% blend of Wyoming Powder River Basin (PRB) coal blended with 20% petroleum coke, and • Each of those fuel supplies blended with 10% biomass

For the COL 3 Unit – • Wyoming PRB coal at 100% of the fuel supply and • Wyoming PRB coal blended with 4% renewable resource fuels (RRF or biomass).

The RRF blends were set at levels that are considered generally acceptable for that type of boiler and at an equivalent level of risk. For the RRF blends, the CO2 output of the RRF was assumed to be zero for this analysis. Sulfur and Nitrogen emissions were adjusted based on analysis values in the RRF fuels. The fuel quality used in this analysis is based on probable annual averages and is intended to be representative of emissions over extended time periods versus permit maximum conditions that maybe experienced only over shorter periods of time.

Based on a literature review of N2O emissions for circulating fluidized bed (CFB) boilers, a revised projection of the N2O emissions has been developed. Based on the review of emissions from operating CFB boilers, the revised estimate for a CFB boiler burning Wyoming PRB is 0.13 Lbs. N2O /MMBtu of fuel input. This data point represents a mid point in the data available for normally operating CFB boilers. The literature indicates that the majority of nitrogen oxide compounds are derived from the fuel bound nitrogen. Based on that, minor adjustments were made to this emission factor to reflect any changes in the nitrogen content of the fuel under the various fuel scenarios.

The emissions review process has also identified that there may be opportunities to reduce the production of N2O from a CFB boiler. The testing data is based on short term testing where the boiler was “tuned” or optimized to reduce N2O. As an example, raising the temperature in the bed of a CFB boiler may reduce the N2O production, but, increase the NOx production and decrease the ability of the limestone to capture sulfur in the bed. This lower potential emission level is provided to illustrate the range that may be achieved by “tuning” the combustion control during operations.

The first set of data tables provide the data for the nominal case, and the latter set of data provides the data for the “tuned” (or optimized) to reduce N2O boiler scenario to portray the probable range for these emissions. For an 80% PRB and 20% petroleum coke fuel blend with co-burning 10% renewable resource fuels, the annual CO2 equivalency emissions for NED 3 are in the estimated range of 2.409 million tons to 2.723 million tons.

Page 2 of 11

Exhibit ____ (RDB-1) Schedule 3

The following table lists the emission rates on a tons per year basis for each of the constituents for the NED 3 (CFB technology) and COL 3 (PC technology) based on normal operating conditions.

Emissions of Green House Gases in tons/year- CFB Optimized for SO2 and NOx

Levelized Plant Startup Plant Plant Heat Fuel Limestone Fuel Net Heat Rate Based Based (Fuel Oil) Boiler Fuel Output Input HHV CO2 CO2 N2O CH4 CO2 MW MMBtu/hr Btu/kWh tons/year tons/year tons/year tons/year tons/year CFB 100% PRB 326.3 3,118 9,556 2,480,000 14,400 1,544 27 1,010 CFB 90% PRB / 10% Wood 326.2 3,122 9,571 2,230,000 13,300 1,429 27 1,010 CFB 80% PRB / 20% Petcoke 326.7 3,084 9,440 2,450,000 46,100 1,645 27 1,010 80% PRB / 20% Petcoke CFB Blend w/ 10% Wood 326.0 3,090 9,479 2,210,000 40,200 1,591 27 1,010

PC 100% PRB 326.2 3,060 9,381 2,430,000 5,900 53 27 1,010 PC 96% PRB / 4% Wood 326.0 3,061 9,390 2,340,000 5,700 53 27 1,010

Note: 1. Based on 87% annual capacity factor. 2. Limestone injection theoretical rate to remove 95% of sulfur in the CFB boiler. 3. Limestone use in Wet FGD system for PC technology was set at a 98% removal rate for SO2. 4. Emissions for the CFB technology are based on detailed engineering analysis of the current boiler configuration and pollution control equipment being developed for bid specifications, and for the PC technology, they are based on similar design parameters for the boiler and previously identified pollution control equipment as part of the conceptual design. (No pollution control is being proposed or considered for N2O control in this analysis). 5. Emission factors for the CFB technology for N2O is based on literature review. 6. Lime (CaO) that maybe utilized in the dry scrubber for NED 3 does not add to onsite CO2 emissions.

Page 3 of 11

Exhibit ____ (RDB-1) Schedule 3

The following table provides the emissions on a tons per year of CO2 equivalent basis for each of the constituents for the NED 3 (CFB technology) and COL 3 (PC technology).

Emissions of Green House Gases in tons/year of CO2 Equivalent-CFB Optimized for SO2 and NOx

CFB 100% PRB 2,480,000 14,400 457,000 621 1,010 1.19 2,490,000 2,950,000

CFB 90% PRB / 10% Wood 2,230,000 13,300 423,000 621 1,010 1.07 2,250,000 2,670,000

CFB 80% PRB / 20% Petcoke 2,450,000 46,100 487,000 614 1,010 1.20 2,500,000 2,985,000

80% PRB / 20% Petcoke CFB Blend w/ 10% Wood 2,210,000 40,200 471,000 617 1,010 1.10 2,250,000 2,723,000

PC 100% PRB 2,430,000 5,900 15,700 610 1,010 0.99 2,440,000 2,454,000

PC 96% PRB / 4% Wood 2,340,000 5,700 15,700 610 1,010 0.95 2,340,000 2,359,000

Note: 1. The CO2 equivalency factor for N2O was set at 296, and for CH4 at 23 times the actual value for the constituent. 2. The “Total CO2 (Only)” column includes all tons that are in the form of CO2 emissions.

Page 4 of 11

Exhibit ____ (RDB-1) Schedule 3

The following table provides an estimate of the emission rates on a tons per year basis for each of the constituents for the NED 3 (CFB technology) and COL 3 (PC technology) based on the CFB boiler being tuned/optimized to reduce N2O emissions.

Emissions of Green House Gases in tons/year- CFB Optimized for N2O

CFB 90% PRB / 10% Wood 326.2 3,122 9,571 2,230,000 13,300 537 27 1,010

CFB 80% PRB / 20% Petcoke 326.7 3,084 9,440 2,450,000 46,100 645 27 1,010 80% PRB / 20% Petcoke CFB Blend w/ 10% Wood 326.0 3,090 9,479 2,210,000 40,200 530 27 1,010

PC 100% PRB 326.2 3,060 9,381 2,430,000 5,900 53 27 1,010

PC 96% PRB / 4% Wood 326.0 3,061 9,390 2,340,000 5,700 53 27 1,010

Note: 1. Based on 87% annual capacity factor. 2. Limestone injection theoretical rate to remove 95% of sulfur in the CFB boiler. 3. Limestone use in Wet FGD system for PC technology was set at a 98% removal rate for SO2.Emissions for the CFB technology are based on detailed engineering analysis of the current boiler configuration and pollution control equipment being developed for bid specifications, and for the PC technology, they are based on similar design parameters for the boiler and previously identified pollution control equipment as part of the conceptual design. (No pollution control is being proposed or considered for N2O control in this analysis). 5. Emission factors for the CFB technology for N2O is based on literature review. Increasing the RRF feed, increasing the firing temperature and other combustion control measures may likely reduce the N2O during actual operations. 6. Lime (CaO) that maybe utilized in the dry scrubber for NED 3 does not add to onsite CO2 emissions.

Page 5 of 11

Exhibit ____ (RDB-1) Schedule 3

The following table provides an estimate of the emissions on a tons per year of CO2 equivalent basis for each of the constituents for the NED 3 (CFB technology) and COL 3 (PC technology) based on the CFB boiler being tuned/optimized to reduce N2O emissions.

Emissions of Green House Gases in tons/year of CO2 Equivalent- CFB Optimized for N2O

Levelized Startup Total Fuel Limestone N2O CH4 Fuel Equivalent Total CO2 Based Based Equivalent Equivalent (Fuel Oil) CO2e (Only) Total CO2 Boiler Fuel CO2 CO2 CO2 CO2 CO2 Production Production Equivalent tons/year tons/year tons/year tons/year tons/year Tons/MWH Tons/Year Tons/Year CFB 100% PRB 2,480,000 14,400 176,000 621 1,010 1.07 2,490,000 2,669,000 CFB 90% PRB / 10% Wood 2,230,000 13,300 159,000 621 1,010 0.97 2,250,000 2,406,000 CFB 80% PRB / 20% Petcoke 2,450,000 46,100 191,000 614 1,010 1.08 2,500,000 2,689,000 80% PRB / 20% Petcoke CFB Blend w/ 10% Wood 2,210,000 40,200 157,000 617 1,010 0.97 2,250,000 2,409,000

PC 100% PRB 2,430,000 5,900 15,700 610 1,010 0.99 2,440,000 2,454,000 PC 96% PRB / 4% Wood 2,340,000 5,700 15,700 610 1,010 0.95 2,340,000 2,359,000

Page 6 of 11

Exhibit ____ (RDB-1) Schedule 3 The following table provides a summary of the auxiliary equipment and mobile equipment that are also sources of the subject emissions of interest for the Nelson Dewey site:

NED 3 CO2 TPY N2O TPY CH4 TPY Emergency Diesel Fire Pump 11 0.000 0.000 Emergency Diesel Generator 46 0.001 0.000 Mobile Sources 1,053 176 64

1. EPA AP-42 factors for No. 2 fuel oil were employed in calculating emissions of CO2, N2O, and CH4 from each piece of equipment utilizing such. 2. The diesel-driven fire pump and emergency diesel generator have not been sized yet, so driver sizes used in the CPCN Application estimates (525 hp and 2,220 bhp) were used to establish consumption rates for emissions. 3. Mobile equipment envisioned to be permanently procured for onsite use at NED 3 include the following: one locomotive (coal train maneuvering); one front-end loader (coal/coke yard), one front-end loader (biomass handling), two heavy-duty trucks (maintenance, miscellaneous hauling), and two light duty trucks (operator and security rounds). 4. EPA AP-42 factors for No. 2 fuel oil and gasoline combusted in mobile sources and test data from California were employed in calculating emissions of CO2, N2O, and CH4 from each piece of mobile equipment. 5. The emissions for the emergency equipment are based solely on the planned periodic testing

As would be expected, the emissions related to the emergency equipment and mobile sources are, in general, not as significant as the boiler-steam generation process. For COL 3, the material handling of the coal will be integrated into the overall coal handling system at the Columbia Energy Center, and as such, it is difficult to develop a specific emissions analysis. Because the same coal handling processes (i.e. coal unloading, stacking, and reclaiming) will in general need to occur for both systems, it is reasonable to assume that the emissions will be similar.

Page 7 of 11

Exhibit ____ (RDB-1) Schedule 3

The Original Data Submittal No. 1-145 is provided below for Reference:

Docket Number: 6680-CE-170 Date of Request: March 9, 2007 Information Requested By: Christine Swailes Date Due: March 30, 2007 Date Responded: April 3, 2007 May 3, 2007 Revised Author: Steve Jackson Author’s Title: Senior Environmental Specialist Author’s Telephone No.: 608-458-5704 Witness: (If other than Author)

Data Request No. 1-145:

1.2.17.4, p. NED 107 and COL 236: List all potential process and input sources for CO2, N2O, and CH4 emissions from the proposed NED 3 and COL 3 plants, including those

associated with other plant inputs besides the coal, pet coke, and biomass fuels, such as limestone. Tabulate the expected resulting greenhouse gas emissions for each proposed plant site.

Response:

COL 3 CO2 TPY N2O TPY CH4 TPY PC Boiler (Fuel Combustion) 2,683,177 60 38 Emergency Diesel Fire Pump 30 1.16E-5 6.60E-2 Page 8 of 11

Exhibit ____ (RDB-1) Schedule 3 Diesel Auxiliary Boiler 9,151 4.51E-2 2.13E-2 Emergency Diesel Generator 129 5.70E-4 7.04E-3 Mobile Sources 23,149 0.7 1 Limestone Injection to WFGD 7,558 0 0 * Assumes 100% PRB * Emissions and Limestone Injection based on 87% capacity * Emission factors used based on AP-42 * Mobile source emissions for heavy trucks and equipment from Transport Canada

Page 9 of 11

Exhibit ____ (RDB-1) Schedule 3

Excerpts of the Original Data Submittal No. 1-139 is provided below for Reference:

Docket Number: 6680-CE-170 Date of Request: March 9, 2007 Information Requested By: Christine Swailes Date Due: March 30, 2007 Date Responded: March 21, 2007 Author: Steve Jackson/Michele Pluta Author’s Title: Author’s Telephone No.: Witness: (If other than Author)

Data Request No. 1-139:

greenhouse gases.

Response:

Note : Only the pertinent section of the original response is provided here. . . . .

Emission GWP (in tons of CO2 equivalent) CO2 1 CH4 23 N2O 296 Intergovernmental Panel on Climate Change, Climate Change 2001: Third Assessment Report

Page 10 of 11

Exhibit ____ (RDB-1) Schedule 3 The following tables provide an estimate in CO2e of the projected greenhouse gas emissions related to the WPL baseload project.

NED3 Greenhouse Gas CO2e Estimate Greenhouse Gas Emission CO2e (tons/year) CO2 2,594,450 2,594,450 CH4 40.5 932 N2O 2,363 699,547 Total 3,294,929

COL3 Greenhouse Gas CO2e Estimate Greenhouse Gas Emission CO2e (tons/year) CO2 2,683,177 2,683,177 CH4 37.6 866 N2O 60.2 17,824 Total 2,701,867

Page 11 of 11

Exhibit ____ (RDB-1) Schedule 3 Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 1-151 Supplemental

Docket Number: 6680-CE-170 Date of Request: March 9, 2007 Information Requested By: Christine Swailes Date Responded: April 3, 2007 May 3, 2007 Supplemental Author: Steve Jackson Author’s Title: Senior Environmental Specialist Author’s Telephone No.: 608-458-5704 Witness: (If other than Author)

Data Request No. 1-151:

1.2.18.1.2, p. NED 110: Identify the design and location, and provide a diagram and map of the proposed lateral well proposed for the NED site and its relationship to the depth of the alluvial aquifer, the Mississippi River bed, and the existing land cover at the well site. DNR has not yet received an application for this well. Submit more extensive groundwater modeling information on proposed operation of this well. Describe what estimated effect the operation of this well will have on rare mussels and other aquatic fauna in the river. Provide source documentation for conclusions.

Response:

Collector Well Details

WPL is providing additional collector well details in the discussion that follows along with the attached diagram and map. The diagram shows the position of the laterals relative to the depth of the alluvial aquifer and the bed of the Mississippi River, and the map shows the location of the well relative to existing land cover.

Well Application

WPL submitted a High Capacity Well Application to WDNR on July 26, 2006, which was deemed incomplete on August 16, 2006. Supplemental permit application materials will be filed at a later date once the well design is developed.

Modeling Information

There is insufficient aquifer data at this time to construct a detailed model; however, preliminary groundwater modeling using a simple MODFLOW model was performed to evaluate impacts due to operation of the collector well. Once a pumping test is

Page 1 of 2 Exhibit ____ (RDB-1) Schedule 3 conducted prior to performing detailed design of the collector well, the model could be refined.

In constructing the preliminary model, the following assumptions were made:

• Q = 3500 gallons per minute

• k (hydraulic conductivity) = 200 feet/day, based on grain-size distribution data from two exploratory test borings drilled at the site

• Aquifer is laterally infinite except to the northeast of the site where a bedrock boundary occurs (coinciding with the Mississippi River valley wall)

• Aquifer thickness is 125 feet at the location of the collector well

The model was run in steady-state mode. Three scenarios were run, one at the assumed value of k, one at one-half the assumed value of k, and one at two times the assumed value of k. Figure 4 in the CPCN application shows the anticipated drawdown due to operation of the collector well.

Impacts to Rare Mussels and Other Aquatic Fauna

There will be no impacts to rare mussels or other aquatic fauna in the river as a result of collector well operation. Impacts to flow in the Mississippi River will be negligible, and the laterals will be over 100 feet below the surface of the river bed.

Supplemental Response:

This supplemental response provides the attachment that was inadvertently omitted from the response dated April 3, 2007.

Page 2 of 2 Exhibit ____ (RDB-1) Schedule 3

Key Map

LEGEND

NED 1 AND NED 2 STATE BORDER NELSON DEWEY STATE PARK NED 3 PREFERRED SITE LAND COVER CLASSIFICATION

WPL PROPERTY AGRICULTURE ADDITIONAL WPL PROPERTY BARREN MUNICIPAL BOUNDARY FORESTED PROPOSED NED 3 LATERAL GRASSLAND COLLECTOR WELL URBAN/DEVELOPED WETLAND NOTE: BOUNDARIES ARE APPROXIMATE WATER

0 200 400 800 WISCONSIN POWER AND LIGHT COMPANY Source: Iowa Department FEET of Natural Resources. 1 INCH EQUALS 400 FEET NED 3 PREFERRED SITE LAND COVER COLLECTOR WELL MAP

\\Espsrv\DATA\DATA2\Projects\WPL\40850_300MW_CPCN & Eng Plan\CPCN\GIS2\NED_LANDCOVER_COLLECTOR_WELL.mxd Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-01

Docket Number: 6680-CE-170 Date of Request: May 24, 2007 Information Requested By: Ken Detmer Date Responded: May 25, 2007 Author: Wisconsin Power and Light Company

Data Request No. 2-01

Provide the Commission with a cost estimate and the time required to update the IGCC technology report (App D).

The Commission would expect this cost to be part of the NED3 CPCN application. Staff is requesting this information in part because this WPSC/WPL technology study date is March 2005 and on p.1-11 it states:

“The IGCC industry is undergoing a period of rapid change. The bulk of the data contained within this study is current as of December 2004. Close attention should be paid to the continued evolution of the IGCC technology and market conditions, with the report updated as required.”

Response:

The current anticipated cost estimate to update the report is less than $75,000. In addition, we currently plan to have a finalized updated report around the end of June 2007 and submit that report in direct testimony, which WPL anticipates will occur around the first part of July 2007.

Page 1 of 1 Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-01

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Wisconsin Power and Light Company Author’s Telephone No.: 608-458-3974 Witness: (If other than Author)

Data Request No. 2-01:

(From page 4 of Version 11B of the Power Plant Filing Requirements (and page 1 of the docket 6680-CE-170 completeness review, PSC REF #70660)):

a) Provide an electronic copy of the application and its appendices in the latest version of Microsoft Word. The CD provided with the revised application contains only *.pdf files. b) Provide electronic copies of all application and appendix Microsoft Excel tables and spreadsheets in the latest version of Microsoft Excel.

Response:

Two (2) compact disks are provided with this response. One disk contains the public version of the updated CPCN application in Microsoft Word format. The second disk contains the confidential version of the updated CPCN application in Microsoft Word format.

At this time, WPL does not have the appendices in word or excel format. However, most documents are searchable pdf files.

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-02

Data Request No. 2-02:

DNR has received nothing WP&L filed as confidential. Wherever the PSC has denied the confidentiality of an item, please deliver that material to DNR as well as uploading it to the PSC’s ERF system.

Response:

The PSC has not denied the confidentiality of any item filed confidentially with the PSC. The Wisconsin Historical Society has now determined, however, that the archeological information contained in the CPCN application is not confidential. The previously marked confidential archeological information (Table 29 and Table 71) is attached hereto and will be provided to the DNR.

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3

CPCN Application NED 3 Preferred Site

Table 29 Historic and Archaeological Sites - NED 3 Preferred Site

Site Cultural Distance from Number Site Name Site Type Affiliation Landform Project Area 800 meters (m) upstream, but Nelson 120 m south of Dewey Early-Late RR corridor 47-GT-1 Village Village Woodland Terrace portion

200 m north of Dewey western end of Mound Mounds (at least Middle - Late RR corridor 47-GT-21 Group 1 25) Woodland Bluffs portion Dewey 800 m upstream, (Newberry) but 10 m south Mound Mounds and of RR corridor 47-GT-22 Group 2 cemetery/burial Woodland Terrace portion

Dewey 180 m north of Mound Mounds - conical, RR corridor 47-GT-27 Group 3 chain, and linear Late Woodland Bluffs portion Fox or Winnebago Terrace & 47-GT-30 NA Village village bluff slope 400 m east 1 kilometer (km) 47-GT-31 NA Mound & Burial Woodland Terrace downstream 47-GT- 411 NA Unknown Unknown Terrace 660 m upstream Late 920 m upstream, Campsite/Village; Woodland; but 180 m south 47-GT- Dietrich Historic dam and Historic of RR corridor 412 Dam artifact scatter Euroamerican Terrace portion 47-GT- 414 NA Unknown Unknown Terrace 40 m upstream Unknown Prehistoric; 47-GT- Campsite/Village; Historic 200 m 416 NA Mill/Sawmill Euroamerican Terrace downstream

Wisconsin Power and Light Company NED-172

Exhibit ___ (RDB-1) Schedule 3

CPCN Application NED 3 Preferred Site

Early and Late Woodland; Campsite/Village; mid-twentieth 47-GT- Kleinpell Vacation century Along east 417 Pines Cottages Euroamerican Terrace boundary Woodland; 47-GT- Historic 700 m 421 NA Artifact Scatter Euroamerican Terrace downstream Terrace 20 m north of 47-GT- Nelson Historic and bluff RR corridor 499 Dewey Homestead Euroamerican base portion Nelson 47-GT- Dewey Historic 689 Park Kiln Kiln Euroamerican Bluff 20 m north

Wisconsin Power and Light Company NED-173

Exhibit ___ (RDB-1) Schedule 3

CPCN Application COL 3 Alternative Site

Table 71 Historic and Archaeological Sites – COL 3 Alternative Site

Site Cultural Distance from Project Number Site Name Site Type Affiliation Landform Area Unknown 47-CO-153 Thurston Campsite Prehistoric Sand Blow 2.36 km south Scott and Campsite/ Unknown 47-CO-154 Berney Village Prehistoric Unknown 1.6 km south Campsite/ Unknown Adjacent to SW corner 47-CO-177 Heinze Village Prehistoric Unknown of survey area 60 m SW of western Villages Unknown point of project area 47-CO-178 Murray (n=2) Prehistoric Unknown (power plant loci) Late Over 700 m west of 47-CO-179 Murray II Mounds Woodland Ridge project area

Unknown Over 700 m west of 47-CO-180 Murray III Campsite Prehistoric Island project area Sone Tree Over 700 m west of 47-CO-181 Camp Sites Campsite Unknown Peninsula project area Indian Unknown Over 700 m west of 47-CO-182 Point Campsite Prehistoric Peninsula project area Unknown 400 m south of project 47-CO-183 NA Unknown Prehistoric Unknown area Island Unknown Over 700 m west of 47-CO-184 Campsite Campsite Prehistoric Sandy Island project area Baerwolf Campsite/ Unknown 350 m NW of project 47-CO-252 Campsite Village Prehistoric Unknown area Unknown Edge of Over 700 m north of 47-CO-57 NA Unknown Prehistoric marsh project area Duck Creek Marsh Unknown Edge of Over 700 m north of 47-CO-69 Mounds Mounds Prehistoric marsh project area Campsites Unknown Edge of Over 700 m north of 47-CO-70 NA (n=2) Prehistoric marsh project area Dead Horse Island Unknown 47-CO-71 Mound Mounds Prehistoric Island 1.7 km to the NE Village & Unknown Over 700 m west of 47-CO-72 NA Cemetery Prehistoric Terrace project area

Wisconsin Power and Light Company COL-372

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-03

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Kevin Vesperman Author’s Title: General Manager - Strategic Resource Deployment Author’s Telephone No.: (608) 458-3141 Witness: (If other than Author)

Data Request No. 2-03:

1.1 Project Description and Overview

1.1.2 Purpose and Need for Power Plant

(ref.1-01 (1.1.2, p. 57)): Provide updated IGCC technology report (App. D). Updated information is needed for the alternatives analysis and the environmental impact statement. (Providing this updated information as part of WP&L’s direct testimony is too late.)

Response:

An update of the report on the status of the integrated coal gasification combined cycle technology is attached. The update was performed by the original authors of the report, Black & Veatch Corporation, a consulting firm based in Kansas City, MO.

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170

Alliant Energy – on behalf of Wisconsin Power and Light and Interstate Power and Light

IGCC Technology Study Update

FINAL REPORT – JUNE 2007 B&V Project Number 148411.0040 B&V File Number 40.0100

June 2007 Black & Veatch Corporation 11401 Lamar Overland Park, Kansas 66211 Tel: (913) 458-2000 www.bv.com

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Alliant Energy – on behalf of WP&L and IPL Docket No. 6680-CE-170 IGCC Technology Study – 2007 Update Table of Contents

Table of Contents

1.0 Overview and Summary of Important Information ...... 1-1 1.1 Project Scope ...... 1-1 1.1.1 Summary of Technologies ...... 1-1 1.1.2 IGCC Availability Issues, Risks, and Mitigation Measures ...... 1-2 1.1.3 IGCC Applicability for Baseload Operation - Current and Future...... 1-2 1.2 Summary of Important Information...... 1-3 1.3 Timeliness of Data Contained within the Study ...... 1-8 1.4 Report Contents ...... 1-8

2.0 Fuel Supply Options ...... 2-1

3.0 IGCC Technologies ...... 3-1 3.1 Gasification Technologies and Suppliers...... 3-1 3.2 Entrained Flow Gasification Process Description ...... 3-4 3.3 Gasification Technology Suppliers...... 3-7 3.4 Gasifier Technology Selection...... 3-10 3.5 Commercial IGCC Experience ...... 3-12 3.6 Fuel Characteristics Impact on Gasifier Selection...... 3-17 3.7 IGCC Performance and Emissions Considerations ...... 3-18 3.8 Gasification Wastewater Treatment...... 3-19 3.9 Acid Gas Removal ...... 3-20

4.0 Gasification Participants and Potential Projects ...... 4-1 4.1 Key Participants in IGCC ...... 4-1 4.1.1 Combustion Turbine Vendors...... 4-1 4.1.2 Steam Turbine and HRSG Vendors...... 4-2 4.1.3 ASU Vendors...... 4-3 4.2 Other Commercial Entrained Bed Gasification Experience ...... 4-4 4.3 Current Announced Electric Generation Industry Activity ...... 4-4 4.3.1 American Electric Power Company...... 4-6 4.3.2 Duke Energy (Cinergy/PSI and Vectren) ...... 4-7 4.3.3 Excelsior Energy, Inc...... 4-9 4.3.4 Southern Company and Orlando Utilities Commission...... 4-10 4.3.5 Global Energy Projects ...... 4-11 4.3.6 The ERORA Group, LLC...... 4-13 4.3.7 Energy Northwest ...... 4-14

June 2007 TC-1 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Alliant Energy – on behalf of WP&L and IPL Docket No. 6680-CE-170 IGCC Technology Study – 2007 Update Table of Contents

4.3.8 NRG Northeast...... 4-15 4.3.9 Summary of Proposed Projects...... 4-15

5.0 Performance and Emissions Estimates ...... 5-1 5.1 Configurations...... 5-1 5.2 Performance ...... 5-2 5.3 Scenarios Selected for Additional Analysis...... 5-2 5.4 IGCC Plant Ramp Rates and Turndown Capability ...... 5-6 5.5 Consumables and Byproducts...... 5-6 5.6 Emissions Estimates...... 5-8 5.6.1 Water Emissions ...... 5-13 5.6.2 Solids Byproducts and Wastes...... 5-13

6.0 Availability and Initial Operation ...... 6-1 6.1 First-Generation IGCC Plants...... 6-1 6.2 Scenarios Selected for Availability Analysis...... 6-3 6.3 Next (Second) Generation IGCC Plants ...... 6-3 6.4 Third-Generation IGCC Plants ...... 6-5 6.5 Other Commercial Entrained flow Gasification Experience ...... 6-5

7.0 Schedule and Site Layout...... 7-1 7.1 Schedule...... 7-1 7.2 Site Layout...... 7-1

8.0 Capital and Operating Cost Estimates ...... 8-1 8.1 Owner’s Costs...... 8-1 8.2 EPC Capital Cost ...... 8-3 8.3 Contracting Methods...... 8-7 8.4 O&M Costs ...... 8-8

9.0 IGCC Status and Advancements for Baseload Generation...... 9-1 9.1 Major Gasification Suppliers ...... 9-1 9.1.1 COP...... 9-1 9.1.2 GE ...... 9-2 9.1.3 Shell ...... 9-2 9.2 IGCC Development Expectations...... 9-3 9.2.1 Plant Capacity Increases ...... 9-3 9.2.2 CTG Efficiency...... 9-3 9.2.3 Plant Emissions...... 9-3

June 2007 TC-2 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Alliant Energy – on behalf of WP&L and IPL Docket No. 6680-CE-170 IGCC Technology Study – 2007 Update Table of Contents

9.2.4 Incentives ...... 9-4 9.2.5 Financing...... 9-5

Appendices

A. IGCC Project Schedule B. IGCC Site Layout Drawing

List of Tables

Table 1-1. IGCC Performance and Cost Estimate Summary (2007)...... 1-7 Table 2-1. As-Received Design Basis Coal Quality...... 2-1 Table 3-1. Comparison of Key Gasifier Design Parameters...... 3-11 Table 3-2. IGCC Projects – All Fuels...... 3-13 Table 3-3. Coal-Based IGCC Demonstration Plants ...... 3-14 Table 3-4. Syngas Characteristics Exiting the Acid Gas Absorber ...... 3-21 Table 4-1. CTG Syngas Performance Estimates...... 4-1 Table 4-2. GE CTG Syngas Experience ...... 4-2 Table 4-3. SPG CTG Syngas Experience ...... 4-3 Table 4-4. Announced IGCC Projects Currently in Development ...... 4-5 Table 5-1. IGCC Configuration Scenarios...... 5-1 Table 5-2. IGCC Performance Estimates at 59° F Ambient Temperature ...... 5-4 Table 5-3. 2x1 7FB IGCC Performance Estimates - Various Ambient Temperatures... 5-5 Table 5-4. 2x1 7FB IGCC Performance Estimates for Natural Gas...... 5-6 Table 5-5. TECO Polk County, Florida Slag Products...... 5-7 Table 5-6. IGCC Emissions Estimates for 600 MW Plant ...... 5-9 Table 5-7. Reported IGCC Emissions for the Polk County, Florida and Wabash, Indiana IGCC Plants...... 5-10 Table 5-8. Flare Emissions Estimates (tons per year)...... 5-12 Table 5-9. Solid Waste Summary ...... 5-14 Table 6-1. Operating Coal/Petcoke Fueled IGCC Plant Reported Availabilities...... 6-2 Table 6-2. Estimated Availabilities for Second Generation of Coal Fueled IGCCs ...... 6-4 Table 6-3. Estimated Forced Outage for Second Generation of Coal Fueled IGCCs .... 6-5 Table 6-4. Estimated Availabilities for Third-Generation Coal Fueled IGCCs ...... 6-6

June 2007 TC-3 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Alliant Energy – on behalf of WP&L and IPL Docket No. 6680-CE-170 IGCC Technology Study – 2007 Update Table of Contents

Table 8-1. Potential Owner’s Costs ...... 8-2 Table 8-2. EPC Capital Cost Estimates ...... 8-6 Table 8-3. Nonfuel Variable O&M Cost Breakdown...... 8-8 Table 8-4. O&M Cost Estimates...... 8-9 Table 8-5. Estimated IGCC Plant Staffing for Two Gasifiers...... 8-10 Table 8-6. Estimated IGCC Plant Staffing for Three Gasifiers...... 8-11 Table 8-7. Estimated IGCC Plant Staffing for Four Gasifiers...... 8-12

List of Figures

Figure 2-1. GE 7FA Co-firing Capability...... 2-2 Figure 3-1. IGCC Process Flow Diagram...... 3-4 Figure 3-2. COP Coal Gasification Process Diagram...... 3-8 Figure 3-3. GE Quench Gasification Process Diagram ...... 3-8 Figure 3-4. GE HTHR (Radiant Cooler) Gasification Process Diagram...... 3-9 Figure 3-5. Shell Coal Gasification Process Diagram ...... 3-9 Figure 3-6. Potential Areas for Integration...... 3-16 Figure 5-1. GE 7FA/7FB Output on Syngas...... 5-3

June 2007 TC-4 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Alliant Energy – on behalf of WP&L and IPL Docket No. 6680-CE-170 IGCC Technology Study – 2007 Update Acronym List

Acronym List

AEP American Electric Power AGR Acid Gas Removal AQCS Air Quality Control System ASU Air Separation Unit BACT Best Available Control Technology CaS Calcium Sulfide

CaSO4 Calcium Sulfate CCPI Clean Coal Power Initiative CCRB Clean Coal Review Board CFB Circulating Fluidized Bed Cl Chloride CO Carbon Monoxide

CO2 Carbon Dioxide COP ConocoPhillips COS Carbonyl Sulfide CPCN Certificate of Public Convenience and Necessity CTG Combustion Turbine Generator DEI Duke Energy Indiana DIPA Diisopropanolamine

DLN Dry-low NOx DOE Department of Energy EFSEC Energy Facility Site Evaluation Council EGEAS Electric Generation Expansion Analysis System EH&S Environmental Health and Safety EIS Environmental Impact Statement EKPC East Kentucky Power Cooperative EPC Engineering, Procurement, and Construction EPRI Electric Power Research Institute FEED Front End Engineering Design FGD Flue Gas Desulfurization GE General Electric

H2 Hydrogen

H2O Water

H2S Hydrogen Sulfide

H2SO4 Sulfuric Acid

June 2007 ACRN-1 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Alliant Energy – on behalf of WP&L and IPL Docket No. 6680-CE-170 IGCC Technology Study – 2007 Update Acronym List

HCl Hydrogen Chloride HCN Hydrogen Cyanide Hg Mercury HGP Hot Gas Path HHV Higher Heating Value HP High-Pressure HRSG Heat Recovery Steam Generator HTHR High Temperature Heat Recovery I&C Instrumentation and Control IDC Interest During Construction IGCC Integrated Gasification Combined Cycle IRP Integrated Resource Plan IURC Indiana Utility Regulatory Commission KBR Kellogg Brown and Root LHV Lower Heating Value LNTP Limited Notice to Proceed LP Low-Pressure MDEA Methyl Diethanol Amine MHI Mitsubishi Heavy Industries MPUC Minnesota Public Utilities Commission

N2 Nitrogen NEPA National Environmental Policy Act NETL National Energy Technology Laboratory NGCC Natural Gas Combined Cycle

NH3 Ammonia

NOx Nitrogen Oxides NPDES National Pollutant Discharge Elimination System NPHR Net Plant Heat Rate

O2 Oxygen O&M Operations and Maintenance OPSB Ohio Power Siting Board OUC Orlando Utilities Commission P&ID Piping and Instrumentation Diagram PC Pulverized Coal petcoke Petroleum Coke PPA Power Purchase Agreement PRB Powder River Basin

June 2007 ACRN-2 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Alliant Energy – on behalf of WP&L and IPL Docket No. 6680-CE-170 IGCC Technology Study – 2007 Update Acronym List

PSC Public Service Commission PSD Prevention of Significant Deterioration PSDF Power Systems Development Facility PTC Production Tax Credit PUC Public Utilities Commission PUCO Public Utilities Commission of Ohio RCRA Resource Conservation and Recovery Act S Sulfur SCGP Shell Coal Gasification Process SCR Selective Catalytic Reduction

SO2 Sulfur Dioxide

SO3 Sulfur Trioxide SPG Siemens Power Generation SRU Sulfur Recovery Unit STG Steam Turbine Generator SW Siemens Westinghouse syngas Synthesis Gas TRIG™ Transport Reactor Integrated Gasification ZLD Zero Liquid Discharge

June 2007 ACRN-3 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Alliant Energy – on behalf of WP&L and IPL Docket No. 6680-CE-170 IGCC Technology Study – 2007 Update Acronym List

Units of Measure

Btu British Thermal Unit ft foot gpm gallons per minute h or hr hour kW kilowatt lb pound ltpd long tons per day (2,240 lb/day) MBtu Million British Thermal Unit MW megawatt MWh megawatt-hour ppb parts per billion ppm parts per million ppmvd parts per million volumetric dry psi pounds per square inch psig pounds per square inch gauge scf standard cubic feet stpd short tons per day (2,000 lb/day) tpd tons per day wt weight yr year

June 2007 ACRN-4 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy -on behalf of WP&L and IPL 1.0 Overview and Summary IGCC Technology Study – 2007 Update of Important Information

1.0 Overview and Summary of Important Information

Black & Veatch was retained to provide an update to the March 2005 coal-based integrated gasification combined cycle (IGCC) facility study. This is part of a broader effort to review the technology choices for a potential new baseload plant owned by Wisconsin Power and Light (WP&L) and Interstate Power and Light (IPL). Recent events in the industry, along with reductions in allowable emissions for coal fueled generating units, have increased interest in coal-based IGCC as a potential technology for the next generation of coal plants. This study investigates the offerings of the three major commercial gasification technology suppliers (ConocoPhillips [COP], General Electric [GE], and Shell) and summarizes the current status of technology development and demonstration. The study also addresses the current and potential benefits and risks associated with IGCC. Major changes from the March 2005 study include a combustion turbine substitution from the GE 7FA combustion turbine generator (CTG) to the GE 7FB and a change in the expected throughput of the GE Quench gasifier. The change to the 7FB increases the nominal net output from 500 to 600 MW. The GE Quench case previously assumed three 50 percent capacity gasifiers, but has now changed to four 33 percent gasifiers. Other differences primarily reflect changes in the marketplace. The cost and performance data developed in this study is of sufficient detail for a technology screening analysis.

1.1 Project Scope This study provides the following information: • A summary of technologies. • An analysis of IGCC availability issues and mitigation measures. • The applicability of IGCC technology for utility baseload generation.

Carbon dioxide (CO2) sequestration was not included in the scope of this study, but provisions were considered for the potential future addition of equipment required for

CO2 capture.

1.1.1 Summary of Technologies Primary applicable gasification technologies are described in this study, with the focus on entrained flow gasifiers. Items covered in this review include the following: • Discussion of major participants in the IGCC industry, including engineering, procurement, and construction (EPC) contractors. • Comparison of key gasifier design parameters.

June 2007 1-1 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy -on behalf of WP&L and IPL 1.0 Overview and Summary IGCC Technology Study – 2007 Update of Important Information

• Suitability of each gasifier for various fuel characteristics. • Performance estimates. • Capital costs and contracting methods. • Operations and maintenance (O&M) costs and considerations. • Emissions control equipment and rates. • Startup and commissioning. • Water and wastewater issues. • Byproduct and waste streams. • CTG, heat recovery steam generator (HRSG), and steam turbine generator (STG) considerations. • Air separation unit (ASU) and other major equipment. • Nontechnical issues such as financing, permitting, and siting. • Conceptual site layout.

1.1.2 IGCC Availability Issues, Risks, and Mitigation Measures The following topics are addressed: • Historical availability of solid fuel IGCC plants. • Major factors that influence availability. • Projected availability of new IGCC facilities. • Experience from gasification-only plants. • Methods to mitigate availability impacts: − Natural gas backup. − Spare gasifier train. • Anticipated future availability levels. The potential risks that are not covered within the capital cost estimate are addressed in Section 6.0. These risks include natural gas required for backup, availability, additional staff required to troubleshoot, additional gasification system starts, and capital improvements for component redesign.

1.1.3 IGCC Applicability for Baseload Operation - Current and Future Section 9.0 discusses the applicability of IGCC technology for utility baseload generation, both today and in the foreseeable future. Key issues challenging the successful implementation of IGCC are identified, along with a description of advances and developments that are being addressed by technology suppliers, engineering and construction contractors, and other parties such as the US Department of Energy (DOE).

June 2007 1-2 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy -on behalf of WP&L and IPL 1.0 Overview and Summary IGCC Technology Study – 2007 Update of Important Information

The potential evolution of the second and third generation of commercial sized facilities is also discussed.

1.2 Summary of Important Information Growing environmental concerns, along with recent changes in the gasification industry, have spurred renewed interest in coal-based IGCC applications among US energy companies. Major industry participants such as American Electric Power (AEP), Duke Energy (formerly Cinergy), and others are developing IGCC projects. In addition, numerous smaller companies are pursuing IGCC using state and federal grants. However, reliability is expected to be lower for an IGCC plant than for a pulverized coal (PC) or circulating fluidized bed (CFB) plant with respect to producing electricity from coal. IGCC plants without spare gasifiers are expected to achieve long- term annual availabilities in the 80 to 85 percent range on coal versus approximately 90 percent for PC and CFB plants. IGCC availability on coal during initial startup and the first several years of operation is expected to be significantly lower. A generation plant that uses IGCC technology could increase the availability by firing the combined cycle portion of the plant on a backup fuel such as natural gas when syngas is not available from coal gasification. The cost, availability, and air emissions of backup fuel firing may limit or prevent its use. If natural gas is not available at the proposed site, the installation of a natural gas pipeline and supporting equipment would be required, which may contribute to higher project capital costs. These potential capital requirements and the higher cost of natural gas as a backup fuel may not be justified by the incremental benefit of increased plant availability and, therefore, may not justify the feasibility of an IGCC project. Likewise, using fuel oil as a backup fuel to enhance syngas production reliability would also be prohibitively expensive and logistically cumbersome. It is generally accepted that initial utility installation of the next generation of IGCC plants may require special financing or cost-sharing arrangements and pre- approval for inclusion in the rate base to generate acceptable cost and risk exposure for the owners. Considering the risk profile, it is anticipated that near-term utility installation of IGCC plants will primarily be undertaken by larger utilities with significant coal-based generation in their existing portfolio that have the expectation that coal generation will be a major part of their future generation. However, it is expected that there will be circumstances in which IGCC would be the preferred choice for utilities that do not meet this generalization. There are four main types of gasifiers that could be considered for this study: namely entrained flow, fixed bed, fluidized bed, and transport bed. However, based upon

June 2007 1-3 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy -on behalf of WP&L and IPL 1.0 Overview and Summary IGCC Technology Study – 2007 Update of Important Information

their characteristics and level of development, entrained flow gasifiers are the best choice for high capacity gasification for power generation. This study focuses on the three entrained flow coal gasification technologies that have been demonstrated in commercial-scale IGCC plants (250 to 300 MW net): • COP • GE • Shell Coal-based IGCC projects, using these gasification technologies, are in development in the United States. Other gasification technologies are under development, but have not progressed toward commercial status as those on the identified list. Some of these technologies are summarized in Section 3.0 of this report. There are three general coal feedstocks typically considered for domestic IGCC projects: Pittsburgh No. 8, Illinois No. 6, and Powder River Basin (PRB). Petroleum coke (petcoke) is a fourth solid fuel feedstock that is frequently considered for IGCC applications. Petcoke is typically a lower cost fuel, but it is not as readily obtained as coal. Alliant Energy has determined, based upon availability and delivered price, that the most likely feedstocks for a new plant in its service territory are Illinois No. 6 and PRB coals. There have been approximately 18 IGCC projects throughout the world that have used various feedstocks, some of which are no longer operating. Of the six operating coal (solid fuel) IGCC plants, four are commercial-scale, entrained flow gasification demonstration projects, ranging in nominal capacity from 250 to 300 MW, and are located in Florida, Indiana, The Netherlands, and Spain. Each of the four entrained flow gasification demonstration projects was government-subsidized. Each of these IGCC plants consists of a single train (one ASU, one gasifier, one gas treating train, and one combined cycle composed of one CTG, one HRSG, and one STG). Each plant experienced numerous problems during its first years of operation. The operation of these four commercial coal fueled IGCC plants has adequately demonstrated capacity, efficiency, and environmental performance, but uncertainty remains regarding availability and capital and O&M costs. The complexity and relative immaturity of the IGCC process increases opportunities for deficiencies in design, vendor-supplied equipment, construction, operation, and maintenance. The high risks of cost overruns and low availability have presented obstacles to the development of coal fueled IGCC projects. Because of their funding methods and demonstration requirements, cost information from these plants does not provide an adequate basis for directly estimating costs for future commercial plants.

June 2007 1-4 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy -on behalf of WP&L and IPL 1.0 Overview and Summary IGCC Technology Study – 2007 Update of Important Information

The next (second) generation of IGCC technology and the market are expected to develop in several critical areas, such as capacity, availability, efficiency, emissions, incentives, and financing. The second generation of coal fueled IGCC plants should take advantage of the “lessons learned” from existing operating plants. IGCC projects are much more complex than PC projects. For IGCC projects, the owners or EPC contractors must integrate technology and equipment from a large variety of suppliers. Gasification technology suppliers primarily license “expertise” in the form of a Process Design Package that is implemented by the owner/EPC contractor. Traditionally, the only equipment provided by the gasification technology supplier consists of a few highly proprietary equipment items. In addition to gasification technology suppliers, there are other critical technology suppliers for an IGCC project, such as the following: • CTG vendors. • ASU vendors. • HRSG vendors. • Gas cleanup technology suppliers. These suppliers are critical to the success of an IGCC plant because of the highly integrated nature of the systems, and the significant capital cost and performance requirements for these system components. GE, Siemens Power Generation (SPG– formerly known as Siemens Westinghouse or SW)), and Mitsubishi Heavy Industries (MHI)1 can supply gasification technology, CTGs, and STG components for a project. Their supply could expand in the future to include some or all of the EPC scope. Currently, it is expected that an EPC wrap will not be available in the near future and, if available, will include a major cost premium. Details regarding guarantee levels for cost, schedule, and performance; associated liquidated damages clauses and risk premiums; and availability assurances are not currently well defined. It is anticipated that guarantee levels will evolve as projects are developed and implemented over the next few years. The current higher project risk of IGCC technology will require higher EPC contractor and owner contingencies than for a supercritical PC project. Both capital and nonfuel O&M costs are currently estimated to be higher for IGCC than for conventional coal fueled units. That difference may be partially offset in some cases by heat rate advantages; however, it is generally acknowledged that improvements in IGCC costs are needed to narrow the comparative capital and O&M costs. There is also a higher degree of uncertainty associated with IGCC costs because of the more limited cost database. When comparing costs, the advantage that IGCC has in

1 MHI is building a demonstration IGCC based on a proprietary gasification technology. This technology will be summarized in Section 3.0.

June 2007 1-5 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy -on behalf of WP&L and IPL 1.0 Overview and Summary IGCC Technology Study – 2007 Update of Important Information

environmental emissions must be considered; this would be particularly pertinent should

CO2 trading or CO2 capture be required. Lending institutions have identified some keys to near-term IGCC project financing, which include accurate cash flow modeling, clear definition of project risk mitigation, and the acquisition of a bankable power purchase agreement (PPA). Second-generation commercial IGCC plants are expected to use GE 7FB, M501F, or enhanced SPG SGT6-5000F (formerly SW 501FD) CTGs. Table 1-1 contains a summary of expected IGCC performance and cost, based on the GE 7FB for the alternatives considered in this study. Performance and cost for the SPG SGT6-5000F are expected to be similar. “G” and “H” class CTGs have the potential to further improve IGCC performance and cost over the next 10 to 20 years. The economics of the GE Quench gasification technology readily lends itself to a spare gasification train. For the purposes of this study, the GE Quench alternative contains a spare gasifier, resulting in higher availability. Alternatively, the GE Quench case could be evaluated without a spare, resulting in reduced capital costs and reduced availability. The third generation of IGCC projects, which is expected to follow several years after the planned second-generation projects, should have evolved to the point that it is a market tested, commercial-scale technology. Risks related to technology maturity, project delivery, and project financing should be well understood so that most of the pitfalls encountered by first-generation projects could be avoided.

June 2007 1-6 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy -on behalf of WP&L and IPL 1.0 Overview and Summary IGCC Technology Study – 2007 Update of Important Information

Table 1-1. IGCC Performance and Cost Estimate Summary (2007)

IGCC Configuration COP COP GE - Quench GE - HTHR Shell Shell Gasifiers (Note 1) 3-33.3% 2-50% 4-33.3% 2-50% 2-50% 2-50% Coal Type PRB Ill. No. 6 Ill. No. 6 Ill. No. 6 PRB Ill. No. 6 Cold Gas Efficiency, HHV, percent (Note 2) 72 77 74 74 83 82 Net Power, MW 609 602 567 599 562 569 IGCC Net Heat Rate, Btu/kWh (HHV) 9,338 8,777 9,723 9,204 8,931 8,659 IGCC Energy Efficiency, percent (HHV) 36.5 38.9 35.1 37.1 38.2 39.4 Total EPC Cost, $MM 1,705 1,505 1,486 1,619 1,574 1,556 Total EPC Cost, $/kW 2,800 2,500 2,622 2,704 2,800 2,735 Owner’s Costs, $MM 853 753 744 810 786 778 Total Project Cost, $MM 2,558 2,258 2,230 2,429 2,360 2,334 Specific Cost, $/kW 4,200 3,750 3,932 4,055 4,200 4,102 Long-Term IGCC Cap Factor, percent 69.7 69.7 76.5 69.7 69.7 69.7 Fixed Operating Cost, $MM/yr 16.8 15.3 17.3 15.3 15.3 15.3 Fixed O&M Cost, $/kW-yr 27.7 25.6 30.7 25.8 27.4 27.1 Variable O&M Cost, $MM/yr (Note 5) 28.5 28.0 28.0 27.5 21.9 25.5 Variable O&M Cost, $/MWh 7.71 7.67 7.43 7.58 6.43 7.41 Total O&M Cost, $MM/yr 45.4 43.4 45.3 42.9 37.3 40.9 Total Nonfuel O&M Cost, $/MWh 12.26 11.86 12.01 11.80 10.92 11.85 Notes: 1. The GE Quench configuration includes a “hot” spare gasifier. 2. All costs are indicative estimates in 2007 US$ and exclude escalation. Accuracy is +30/-20 percent. 3. Cold gas efficiency is the ratio of the syngas fuel value to the coal fuel value after sulfur removal, generally expressed in HHV (Higher Heating Value). 4. Variable O&M cost is an average over a 25 year plant operating life in 2007 US$ without escalation and without major equipment replacement.

June 2007 1-7 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 1.0 Overview and Summary IGCC Technology Study – 2007 Update of Important Information

1.3 Timeliness of Data Contained within the Study The IGCC industry is undergoing a period of rapid change. The bulk of the data contained within this study is current as of June 2007. Close attention should be paid to the continued evolution of the IGCC technology and market conditions, with the report updated as required.

1.4 Report Contents This study is organized in the following manner: • Section 1.0, Overview and Summary of Important Information. • Section 2.0, Fuel Supply Options. • Section 3.0, IGCC Technologies. • Section 4.0, Gasification Participants and Potential Projects. • Section 5.0, Performance and Emissions Estimates. • Section 6.0, Availability and Initial Operation. • Section 7.0, Schedule and Site Layout. • Section 8.0, Capital and Operating Cost Estimates. • Section 9.0, IGCC Status and Advancements for Baseload Generation.

June 2007 1-8 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 2.0 Fuel Supply Options

2.0 Fuel Supply Options

Alliant Energy has determined, based upon availability and delivered price, that the most likely feedstocks for a new plant in its service territory are Illinois No. 6 and PRB coals. Therefore, this IGCC evaluation was performed assuming the use of these two coals. The design basis coal qualities, taken from the March 2005 Study, are shown in Table 2-1.

Table 2-1. As-Received Design Basis Coal Quality

Coal Description Illinois No. 6 PRB Heat Content, Btu/lb HHV 10,400 8,378 Sulfur, percent wt 3.2 0.36 Ash, percent wt 10.6 5.1 Moisture, percent wt 13 30

The Illinois Basin encompasses bituminous coal production extending across central and southeastern Illinois, western Kentucky, and southwestern Indiana. It has many coal seams, most notably the Illinois No. 2, Illinois No. 5, Illinois No. 6, and Kentucky No. 9 seams. Illinois Basin coal can vary substantially in sulfur (1.6 to 3.4 percent by weight), ash (6.0 to 14.3 percent), moisture (5.0 to 14.1 percent), and heat content (10,200 to 12,800 Btu/lb HHV). The PRB region comprises all or parts of eight counties in Wyoming and six counties in Montana, with current production concentrated in Campbell and Converse counties in Wyoming and Big Horn and Rosebud counties in Montana. The majority of the current production of PRB coal is from Campbell County, Wyoming. PRB coal is low sulfur subbituminous coal and ranges in heating value from about 7,500 to 9,700 Btu/lb, with current Wyoming PRB production generally between 8,200 and 8,900 Btu/lb. For this study, Wyoming PRB coal was assumed to be the supply source for the coal and, therefore, the nominal values shown in Table 2-1 and elsewhere in this document are intended to be representative of Wyoming PRB coal. If synthesis gas (syngas) produced by the gasifier is not available to fully power the CTGs, a backup fuel such as natural gas or oil can be used. The net plant heat rate (NPHR) of an IGCC plant firing 100 percent natural gas is roughly 7,600 Btu/kWh HHV (without duct firing), which is about 15 percent higher than a combined cycle plant designed for natural gas operation only. This heat rate is approximately 7.5 percent higher than a conventional natural gas fired combined cycle that is utilizing steam

June 2007 2-1 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 2.0 Fuel Supply Options injection for power augmentation and duct firing. Nitrogen oxides (NOx) emissions could be higher when burning backup fuels than for natural gas combined cycle (NGCC) operation, unless there was a selective catalytic reduction (SCR) system installed. Figure 2-1 illustrates the GE 7FA CTG capability to co-fire syngas and natural gas. The dual burners allow for 100 percent syngas operation, 100 percent natural gas operation, or a co-firing where between 10 and 70 percent of the heat input can come from natural gas. It is anticipated that the GE 7FB, SGT6-5000F, and the MHI 501F CTGs would have similar capabilities.

Figure 2-1. GE 7FA Co-firing Capability2.

2 From a presentation by Norman Shilling, GE Energy, at the 3rd US-China Clean Energy Workshop on October 18-19, 2004, at the National Research Center for Coal and Energy (NRCCE) in Morgantown, WV. This meeting was sponsored by the NRCCE, the US DOE, and the US China Energy & Environmental Technology Center.

June 2007 2-2 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies

3.0 IGCC Technologies

IGCC is a promising future technology for coal fueled generation, offering the potential for lower emissions than conventional coal fueled generation technologies. However, reliability is expected to be lower for an IGCC plant than for a PC or CFB plant with respect to producing electricity from coal. IGCC plants without spare gasifiers are expected to achieve long-term annual availabilities in the 80 to 85 percent range on coal versus approximately 90 percent for PC and CFB. IGCC availability on coal during initial startup and the first several years of operation is expected to be significantly lower. A generation plant that uses IGCC technology could increase the availability by firing the combined cycle portion of the plant on a backup fuel (such as natural gas) when syngas is not available from coal gasification. The cost, availability, and air emissions of backup fuel firing may limit or prevent its use. If natural gas is not available at the proposed site, the installation of a natural gas pipeline and supporting equipment would be required, which may contribute to higher project capital costs. These significant capital requirements may not be justified by the incremental benefit of increased plant availability with higher cost natural gas as a backup fuel, and may not justify the feasibility of an IGCC project. Likewise, using fuel oil as a backup fuel to enhance syngas production reliability would also be prohibitively expensive and logistically cumbersome. Cost, schedule, and plant availability issues cause IGCC projects to have higher financial risk than conventional PC or CFB power generation projects. Details regarding the guarantee levels for cost, schedule, and performance; the associated liquidated damages clauses and risk premiums; and availability assurances are not well defined at this time. It is expected that the standards for contractual arrangements between owners and constructors will evolve, based on the experiences of the next generation of IGCC project development.

3.1 Gasification Technologies and Suppliers Gasification is a mature technology with a history that dates back to the 1800s. The first patent was granted to Lurgi GmbH in Germany in 1887. By 1930, coal gasification had become widespread and in the 1940s, commercial coal gasification was used to provide “town” gas for streetlights in both Europe and the United States. Currently, there are four main types of gasifiers: • Entrained flow • Fixed bed • Fluidized bed

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies

• Transport bed The following listing includes the most notable technology suppliers by type: • Entrained Flow Gasifiers: – ConocoPhillips (COP) (E-Gas, formerly Global Energy, originally Dow-Destec). – General Electric (GE) (formerly ChevronTexaco, originally Texaco). – Mitsubishi Heavy Industries (MHI). – Shell. – SPG GSP (formerly Noell). • Fixed Bed (or Moving Bed) Gasifiers: – BGL (slagging, Global Energy, formerly British Gas Lurgi). – Lurgi (dry bottom). • Fluidized Bed Gasifiers: – Carbona (formerly Tampella). – HTW (formerly High Temperature Winkler). – KRW. – Lurgi. • Transport Bed Gasifiers: – Kellogg Brown and Root (KBR). Entrained flow gasifiers have been operating on oil feedstock since the 1950s and on coal and petcoke feedstock since the 1980s. Entrained flow gasifiers operate at high pressure (HP) and temperature, have very low fuel residence times, are either oxygen- blown (COP, GE, Shell, and SPG) or air blown (MHI), and have high feedstock capacity throughputs. Fixed bed gasifiers have operated on coal feedstock since the 1940s. Compared to entrained flow gasifiers, fixed bed gasifiers operate at lower pressure and temperature, have much longer fuel residence times, and have lower capacity throughputs. Fluidized bed gasifiers have operated on coal since the 1920s. Compared to entrained flow gasifiers, fluidized bed gasifiers operate at lower pressure and temperature, only use air, have longer fuel residence times, and have lower capacity throughput. Transport bed gasifiers have only recently been tested on a small scale. Compared to entrained flow gasifiers, transport gasifiers operate at lower pressure and temperature, only use air, have longer fuel residence times, and have lower capacity throughput. Limestone is fed with coal to fluidized bed and transport bed gasifiers for capturing some of the sulfur as calcium sulfide (CaS), which is typically oxidized to calcium sulfate (CaSO4) for landfill disposal. Raw syngas from gasification is treated to

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies

remove sulfur-containing constituents as elemental sulfur or sulfuric acid (H2SO4), which can be sold. The ash from fluidized bed, transport bed, and dry bottom fixed bed gasifiers is leachable and is typically landfilled. Entrained flow and slagging fixed bed gasifiers operate above the ash fusion temperature and produce a nonleachable slag that can be sold. Entrained flow and fixed bed gasifiers generally use high purity oxygen as the oxidant. Fluidized bed and transport gasifiers use air instead of high purity oxygen. Since high purity oxygen does not contain the large concentration of nitrogen present in air, equipment size can be reduced commensurately. Higher gasifier operating pressures are also more economical for the smaller gas flow rates and equipment size associated with high purity oxygen use. Entrained flow gasifiers have higher operating temperatures and lower residence times than fluidized and transport bed gasifiers. These conditions require the use of high purity oxygen for entrained flow gasifiers. An oxygen purity of 95 percent by volume is the optimum for entrained flow gasifiers producing syngas for combustion turbine fuel. An exception is the MHI entrained flow gasifier, which uses oxygen-enriched air for IGCC power generation. Oxygen purities of 98 percent or higher are required when the syngas is used to produce chemicals and liquid fuels. Entrained flow gasifiers are relatively new technologies compared to fluidized bed and fixed bed gasifiers. Entrained flow gasifiers have been operating successfully on solid fuels since the mid-1980s to produce chemicals and, since the mid-1990s, to produce electricity in four 250 to 300 MW commercial-scale IGCC demonstration plants located in Europe (two units) and the United States (two units). Transport bed gasification technology is a recent development that has not yet been demonstrated on a commercial scale. The Southern Company and KBR have been testing a 30 tons per day (tpd) air-blown transport reactor integrated gasification (TRIG) system at the US DOE-funded Power Systems Development Facility (PSDF) at Wilsonville, Alabama. TRIG employs KBR catalytic cracking technology, which has been used successfully for more than 50 years in the petroleum refining industry. In 2004, the US DOE awarded $235 million to the Southern Company and the Orlando Utilities Commission (OUC) to build a 285 MW IGCC Plant at the Stanton Energy Center in Florida to demonstrate TRIG combined cycle technology under the Clean Coal Power Initiative (CCPI) program. The total cost of this plant is estimated to be $792 million. The proposed plant will gasify subbituminous coal. Southern Company estimates that the plant heat rate will be approximately 8,400 Btu/kWh (HHV coal)3. The demonstration plant is scheduled to start up in or after 2010. Results from this

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies

commercial-scale demonstration plant should determine whether TRIG technology will be competitive with entrained flow gasifier technology. At this time, based on their characteristics and level of development, oxygen- blown entrained flow gasifiers are assumed to be the best choice for high capacity gasification for power generation.

3.2 Entrained Flow Gasification Process Description A commercially available IGCC process flow diagram is shown on Figure 3-1.

BFW Flue Gas

Fuel Fluxant Superheated Heat Steam or Water Steam Recovery BFW Steam Steam Coal & Saturated Steam Turbine Fluxant Generation Handling (HRSG) Water Clean Hot Turbine Flue Gas Exhaust Gas

Fuel Gas Gas Acid Gas Combustion Electric Gasification Cooling Scrubbing Removal Turbines Generators

Oxygen Air Extraction Air Air Separation Substation Nitrogen T&D Wastewater Sulfur Treating Recovery Air Slag

Salt Sulfur Figure 3-1. IGCC Process Flow Diagram

Gasification consists of partially oxidizing a carbon-containing feedstock (solid or liquid) at a high temperature (2,500 to 3,000° F) to produce a syngas consisting primarily of carbon monoxide (CO) and hydrogen. A portion of the carbon is completely oxidized to CO2 to generate sufficient heat required for the endothermic gasification reactions.

(The CO2 proportion in the syngas from the gasifier ranges from 1 percent for the dry feed Shell, SPG, and MHI gasifiers to more than 15 percent for the slurry feed COP and GE gasifiers.) The gasifier operates in a reducing environment that converts most of the

sulfur in the feed to hydrogen sulfide (H2S). A small amount of sulfur is converted to carbonyl sulfide (COS). Some sulfur remains in the ash, which is melted and then quenched to produce slag. Other minor syngas constituents include ammonia (NH3), hydrogen cyanide (HCN), hydrogen chloride (HCl), and entrained ash, which contains unconverted carbon. In IGCC applications, the gasifier pressure is typically 450 to 550 pounds per square inch gauge (psig). This pressure is set by the combustion turbine June 2007 3-4 © Black & Veatch 2007 Final Report All Rights Reserved

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies syngas supply pressure requirements. GE gasifiers can operate at higher pressures, up to 1,000 psig, and the excess syngas pressure is let down in an expander to produce additional power. A fluxant may need to be fed with the coal to control the slag viscosity so that it will properly flow out of the gasifier. Fluxant addition is typically less than 2 percent of the coal feed. The fluxant can be limestone, PC boiler ash, or, in some cases, soil. The required fluxant composition and proportion will vary with the coal feed composition. The gasification process operators must know the feed coal composition and make fluxant adjustments when the coal composition changes. Too little fluxant can allow excessive slag to accumulate in the gasifier, which could damage the refractory and eventually choke the gasifier. Too much fluxant can produce long cylindrical slag particles instead of small slag granules when the slag is quenched in the lockhopper. These long thin slag particles will plug up the slag lockhopper. Solid fuel feeds to the gasifier can be dry or slurried. Solid fuels slurried in water do not require the addition of steam for temperature moderation. While slurries typically use water, oil can also be used. Steam is added to the oxygen as a temperature moderator for dry solid feed gasifiers, solid feeds slurried in oil, and oil feed gasifiers. Entrained flow gasifiers using oxygen produce syngas heating values in the range of 250 to 300 Btu/scf on an HHV basis4. Oxygen is produced cryogenically by compressing air, cooling and drying the air, removing CO2 from the air, chilling the feed air with product oxygen and nitrogen, reducing the air pressure to provide autorefrigeration and liquefy the air at -300° F, and separating the liquid oxygen and liquid nitrogen by distillation. Air compression consumes a significant amount of power, between 7 and 10 percent of the IGCC gross power output.

Hydrogen in syngas prevents the use of dry-low NOx (DLN) combustors in the combustion turbines. Dilution of the syngas to reduce flame temperature is required for

NOx control. Syngas is typically diluted by adding water vapor and nitrogen. Water vapor is added to the syngas by evaporating water using low level heat. Depending on the combustion turbine used, nitrogen is added by compressing excess nitrogen from the ASU and adding it to the syngas either upstream of the combustion turbine or by injection into the combustion turbine. GE combustion turbines inject this diluent nitrogen separately from the syngas, into the same ports used for steam or water injection. For MHI and SPG combustion turbines, diluent nitrogen is premixed with the syngas.

Syngas dilution for NOx control increases the mass flow through the combustion turbine, which also increases power output. The nitrogen supply pressure required for injection into a GE 7FB is 405 psia versus 450 to 500 psia for mixing with the syngas for

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies

the MHI 501F and the SPG SGT6-5000F (formerly known as the SW 501FD). The diluted syngas has a heat content of 120 to 150 Btu/scf. However, the mass flow of the diluted syngas is eight times that of natural gas, which increases the combustion turbine power output by up to 16 percent, when no air is extracted for the ASU. A portion of the combustion turbine compressed air may be extracted for feed to the ASU. The ASU and combined cycle are integrated by the nitrogen and air exchanges. Extracting compressed air from the combustion turbine improves overall efficiency, but it adds complexity to the process (including longer startup periods), if there is no separate source of startup compressed air. The prevailing thought is to minimize or avoid compressed air integration. In the non-quench gasifier designs, the raw hot syngas is cooled by the boiler feedwater from the HRSG to a temperature suitable for cleaning. The syngas cooling process generates saturated steam that is subsequently integrated back into the steam cycle. The steam quantities and pressures vary with the gasification process design.

Before the raw syngas enters the combustion turbine combustor, the H2S, COS,

NH3, HCN, and particulates must be removed. Cooled syngas is scrubbed to remove

NH3, water soluble salts, and particulates. Syngas may also be filtered in ceramic candle filters, or sintered metal filters to remove additional particulates. Syngas is filtered in ceramic candle filters at the Buggenum and Puertollano IGCC plants. At the Wabash IGCC plant, syngas was initially filtered in ceramic candle filters; later, the filter elements (candles) were changed to sintered metal. The syngas filters at the Buggenum, Puertollano, and Wabash plants are located upstream of the acid gas removal (AGR) equipment. At the Polk County IGCC plant, syngas is filtered in cartridge filters downstream from the AGR equipment.

COS in the syngas is hydrolyzed by a catalyst to H2S, which is removed from the syngas by absorption in a solvent. This absorption process is called acid gas removal

(AGR). The H2S that is removed from the syngas by absorption in a solvent is desorbed as a concentrated acid gas when the solvent is regenerated, by lowering its pressure and increasing its temperature. Descriptions of commercial AGR systems are provided in Section 3.9. The acid gas stream is typically converted to elemental sulfur in the Claus sulfur recovery process, although it is also possible to produce sulfuric acid. The primary chemical reaction in the Claus process is the reaction of H2S and sulfur dioxide (SO2) to produce elemental sulfur and water. This reaction requires a catalyst and is performed in two stages. The SO2 is produced by oxidizing (burning) one third of the H2S in the feed gas. External fuel is only needed to initially heat up the Claus thermal reactor and initiate

combustion of the acid gas. Under normal operation, the oxidation of H2S provides

sufficient heat to maintain the reaction. The sulfur is formed as a vapor; the S2 form of

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies

sulfur reacts with itself to produce S6 and S8, which are subsequently condensed. This condensed liquid sulfur is separated from the residual gas and stored in a pit at 275° to 300° F. As required, the liquid sulfur is pumped from the pit to railcars for shipment. Solid sulfur can be produced in blocks or pellets by cooling the liquid sulfur to ambient

temperature. The residual (tail gas) is primarily CO2 and nitrogen, which are compressed and reinjected into the syngas upstream of the AGR.

3.3 Gasification Technology Suppliers There are four entrained flow gasification technologies that use oxygen to produce syngas and nitrogen diluent for combustion turbine fuel in an IGCC configuration: • COP, which licenses E-Gas technology that was developed by Dow. COP purchased this technology from Global Energy in August 2003. • GE, which purchased Texaco gasification technology from ChevronTexaco in June 2004. • Shell, which developed its gasification technology in conjunction with Prenflo. Prenflo technology is no longer licensed. • SPG, which purchased GSP gasification technology from Sustec in May 2006. In an attempt to lower the inherently high auxiliary load needed for oxygen-blown gasifiers, a fifth entrained flow gasifier producer, MHI, has developed a two-stage pressurized air-blown gasifier that is expected to complete its first test run on a 250 MW IGCC demonstration plant in Japan by the end of 2007. SPG (formerly Sustec GSP, FutureEnergy, and Noell) has one small gasification plant (Schwarze Pumpe, 200 MWth methanol and power cogeneration). Its technology has been geared toward biomass and industrial processing on a smaller scale, but it appears to be making an entry into the utility-scale power generation market. Two 500

MWth SPG gasifiers are in construction in China for the production of dimethylether (DME) from bituminous coal; these gasifiers are scheduled to start up in 2008. The 500

MWth gasifier is currently the largest offered by SPG. This size of gasifier will supply 62 percent of the syngas required by a SGT6-5000F combustion turbine. This study focuses on the four entrained flow coal gasification technologies that have been demonstrated in commercial-scale IGCC plants (250 to 300 MWnet): • COP. • GE (Quench and Radiant). • Shell. Process flow diagrams for each of these gasification technologies are shown on Figures 3-2, 3-3, 3-4, and 3-5, respectively. June 2007 3-7 © Black & Veatch 2007 Final Report All Rights Reserved

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies

Recycle Syngas

Raw Syngas

Slag Figure 3-2. COP Coal Gasification Process Diagram5

Figure 3-3. GE Quench Gasification Process Diagram6

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies

Figure 3-4. GE HTHR (Radiant Cooler) Gasification Process Diagram7

Figure 3-5. Shell Coal Gasification Process Diagram8

7 Texaco Coal Gasification Process Brochure. HTHR = High Temperature Heat Recovery. 8 “The Shell Coal Gasification Process for the US Industry,” van der Ploeg, HJ; Chhoa, T and Zuideveld, PL; GTC Washington DC, October 2004. June 2007 3-9 © Black & Veatch 2007 Final Report All Rights Reserved

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The COP and GE gasifiers are refractory lined with coal-water slurry feed. In the late 1970s, Shell and Krupp-Koppers jointly developed a waterwall type gasifier with dry, pulverized coal feed specifically for IGCC power generation for a 150 long tons per day (ltpd) demonstration plant near Hamburg, West Germany. During the 1990s, Shell and Krupp-Koppers licensed their gasification technology separately. The Puertollano, Spain IGCC plant, which was built in the mid-1990s, uses Krupp-Kopper’s Prenflo gasification technology. In the late 1990s, Krupp-Koppers merged with Uhde, and Uhde reached an agreement with Shell to license Shell gasification technology and no longer market the Prenflo gasification process. Uhde has incorporated its Prenflo experience into Shell’s coal gasification process technology. Each of the three commercial, entrained flow coal gasification technologies generates similar syngas products. All three gasifiers react the coal with oxygen at HP and temperature to produce syngas consisting primarily of hydrogen and CO. The raw syngas from the gasifier also contains CO2, water, H2S, COS, NH3, HCN, and other trace impurities. The syngas exits the gasifier reactor at approximately 2,500° to 2,900° F. Each of the COP, GE, and Shell gasification processes cools the hot syngas from the gasifier reactor differently. In the COP process, the hot syngas is partially quenched with coal slurry, resulting in a second stage of coal gasification. The raw syngas from the COP gasifier may also contain methane and products of coal devolatilization and pyrolysis because of its two-stage gasification process. The partially quenched syngas is cooled with recycled syngas to solidify the molten fly slag and then further cooled to produce HP steam in a vertical shell and tube heat exchanger. (Syngas flow is down through the tubes. Boiler water and steam flow is up through the shell side.) Unconverted coal is filtered from the cooled syngas and recycled to the gasifier’s first stage. GE has two methods for cooling the hot syngas from the gasifier: radiant cooling to produce HP steam via high temperature heat recovery (HTHR) and water quench with low-pressure (LP) steam generation. In the Shell process, hot syngas is cooled with recycled syngas to solidify the molten fly slag and then further cooled in a convective cooler to produce high temperature steam. The cooled, raw syngas is cleaned by various treatments, including filtration, scrubbing with water, catalytic conversion, and scrubbing with solvents, as discussed in Section 3.8. The clean syngas that is used as combustion turbine fuel contains hydrogen,

CO, CO2, water, and parts per million (ppm) concentrations of H2S and COS.

3.4 Gasifier Technology Selection Table 3-1 provides process design characteristic data for the COP, GE, and Shell gasification technologies for systems that would generally be considered for a nominal

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies

600 MW IGCC facility. The Shell gasification technology has the highest cold gas efficiency, because the gasifier feed coal is injected into the gasifier dry, whereas with the COP and GE gasifiers, the feed is a slurry of coal in water. However, the Shell dry feed coal gasification process has a higher capital cost. Cooling the hot syngas to produce HP steam also contributes to higher IGCC efficiency, but with a higher capital cost. Shell and COP generate HP steam from syngas cooling. GE offers both HP steam generation using Radiant syngas coolers and LP steam generation using its Quench process, which has a significantly lower capital cost than the Radiant process. The COP and GE gasifiers are refractory lined, while the Shell gasifier has an inner water tube wall (membrane). The refractory-lined gasifiers have a lower capital cost, but the refractory requires frequent repair and replacement. The COP and GE gasifier burners typically require more frequent replacement than the Shell gasifier burners.

Table 3-1. Comparison of Key Gasifier Design Parameters

Technology COP GE Quench GE HTHR Shell

Gasifier Feed Type Slurry Slurry Slurry Dry N2 Carrier Gasifier Burners Two Stage: First Single Stage-- Single Stage-- Single Stage-- Stage--Two One vertical One vertical Four to eight horizontal burners burner burner horizontal burners Second Stage--One horizontal feed injector w/o O2 Gasifier Vessel Refractory lined Refractory lined Refractory lined Waterwall membrane Syngas Quench Coal Slurry and Water None Recycle Gas Recycle Gas Syngas Heat Firetube Quench Radiant Watertube Recovery HP WHB LP WHB HP WHB HP WHB Coal Cold Gas 71 to 80 percent 69 to 77 percent 69 to 77 percent 78 to 83 percent Efficiency, HHV Coal Flexibility Middle Low Low High Capacity, stpd 3,000 to 3,500 2,000 to 2,500 2,500 to 3,000 4,000 to 5,000

WHB--Waste Heat Boiler; stpd--short tons per day.

It is worth mentioning gasifier sizing issues with respect to the gasification technologies. Shell has stated that its maximum gasifier capacity is 5,000 metric tons per day (mtpd) of dried coal. GE offers gasifiers in standard sizes: 450, 750, 900, and 1,800 ft3. The largest Radiant gasifier that GE currently offers is 1,800 ft3. Shell, GE

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies

(Radiant), and COP currently offer a gasifier that will supply sufficient syngas for a GE 7FB, or SPG SGT6-5000F, or MHI 501F combustion turbine. The largest Quench gasifier that GE currently offers is 900 ft3. The maximum capacity of this gasifier is less than 2,500 tpd of as-received coal, and it produces about 74 percent of the syngas combusted by a GE 7FB or SPG SGT6-5000F combustion turbine at ISO conditions. Overall, energy conversion efficiencies for IGCC plants vary with the gasification technology type, system design, level of integration, and coal composition. The gasifier efficiency of converting the coal fuel value to the syngas fuel value (after sulfur removal) is known as the cold gas efficiency, which is generally expressed in HHV. The values for cold gas efficiency in Table 3-1 are indicative of the range of achievable performance for coal and petcoke. Cold gas efficiency for the Shell dry coal feed process is about 4 percent higher than the coal-water slurry feed gasification processes for low moisture coal. This difference increases with the coal’s moisture content. HP steam generation from syngas cooling increases IGCC efficiency by about 2 percent over that of water quench.

3.5 Commercial IGCC Experience There have been approximately 18 IGCC projects throughout the world, as listed in Table 3-2. Of these, 15 were based on entrained flow gasification technology. Nine of the projects are coal-based, two petcoke-based, one sludge-based, and the other six oil- based. Two of the coal-based IGCC plants, Cool Water in California and the Dow Chemical Plaquemine Plant in Louisiana, were small demonstration projects and have been decommissioned. Another small coal IGCC demonstration project was Sierra Pacific’s Piñon Pine Project in Nevada. This project, based on KRW fluidized bed technology, was not successful. Of the six operating coal IGCC plants, one is a 40 MW plant that coproduces methanol using an SPG gasifier, one is a 350 MW lignite cogeneration plant that has 26 Lurgi fixed bed gasifiers, and four are commercial-scale, entrained flow gasification demonstration projects (ranging in capacity from 250 to 300 MW) located in Florida, Indiana, The Netherlands, and Spain. The Wabash Indiana IGCC plant did not operate for an extended period in 2004 and 2005 because of contractual problems, but is currently back in operation. Design data for these four demonstration plants are listed in Table 3-3. Each of the four projects was a government-subsidized IGCC demonstration, two in the United States and two in Europe. Each of these IGCC plants consists of a single train (one ASU, one gasifier, one gas treating train, and one combined cycle consisting of one CTG, one HRSG, and one STG). Wabash has a spare gasifier. Each plant experienced numerous problems during its first years of operation, as discussed further in Section 6.0. June 2007 3-12 © Black & Veatch 2007 Final Report All Rights Reserved

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies

Table 3-2. IGCC Projects – All Fuels

Owner - Location Year1 MW Application Fuel Gasifier SCE Cool Water2 – USA (CA) 1984 120 Power Coal Texaco (GE) Dow LGTI Plaquemine –Plaquemine2 1987 160 Cogen Coal Destec

- USA (LA) (COP) Nuon Power – Netherlands 1994 250 Power Coal Shell PSI/Global Wabash – USA (IN) 1995 260 Repower Coal E-Gas (COP) TECO Polk County – USA (FL) 1996 250 Power Coal Texaco (GE) Texaco El Dorado3 – USA (KS) 1996 40 Cogen Petcoke Texaco (GE) SUV - Czech Republic 1996 350 Cogen Coal Lurgi5 Schwarze Pumpe - Germany 1996 40 Power/ Methanol Lignite SPG GSP Shell Pernis Refinery - Netherlands 1997 120 Cogen/Hydrogen Oil Shell Elcogas - Spain 1998 283 Power Coal/Petcoke Prenflo Sierra Pacific4 – USA (NV) 1998 100 Power Coal KRW6 - Air ISAB Energy - Italy 1999 500 Power/Hydrogen Oil Texaco (GE) API - Italy 2000 250 Power/Hydrogen Oil Texaco (GE) Delaware City Refinery - USA (DE) 2000 180 Repower Petcoke Texaco (GE) Sarlux/Sara Refinery - Italy 2000 550 Cogen/Hydrogen Oil Texaco (GE) ExxonMobil - Singapore 2000 180 Cogen/Hydrogen Oil Texaco (GE) FIFE - Scotland 2001 120 Power Sludge BGL5 NPRC Negishi Refinery - Japan 2003 342 Power Oil Texaco (GE) Notes: 1. First year of operation on syngas. 2. Retired. 3. The El Dorado Refinery is now owned by Frontier Refining. 4. Not successful. 5. Fixed bed. 6. Fluidized bed.

Table 3-3 also summarizes the integration in each plant. Basically, there are three major areas for potential integration: • Water and steam between the power generation area and the gasification island. High and low level heat rejection from the gasification process is utilized to produce combined cycle power. • The nitrogen side of the ASU and CTG--Waste nitrogen is mixed with the

syngas to reduce NOx formation and to increase power output. • The air side of the ASU and the CTG--Air is extracted from the CTG compressor to reduce the auxiliary power and increase efficiency.

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies

Table 3-3. Coal-Based IGCC Demonstration Plants1

Project Nuon Power Wabash 3 TECO Polk County 4 Elcogas 5 Location Buggenum, Netherlands Indiana Florida Puertollano, Spain Technology Shell E-Gas (COP) Texaco (GE) Prenflo (Krupp) Startup Year 1994 1995 1996 1998 HHV Efficiency, net design, 41.4 37.8 39.7 41.5 percent Height, ft 246 180 295 262 Fuel, design Coal Coal Coal 50% coal/50% petcoke Fuel Consumption, tpd 2,000 2,200 2,200 2,600

Fuel Feed Dry N2 lockhopper Wet slurry Wet slurry Dry N2 lockhopper Syngas HHV, Btu/scf 300 276 266 281 CTG Model SPG V94.2 GE 7FA GE 7FA SPG V94.3 Firing temperature, °F 2,012 2,300 2,300 2,300 Combustors Twin vertical silos Multiple cans Multiple cans Twin horizontal silos CTG Output, design, MW 155 192 192 200 STG Output, design, MW 128 105 121 135 Auxiliary Power, design, MW 31 35.4 63 35 Net Output, design, MW 252 262 250 3005 Net Output, achieved, MW 252 252 250 283 NPHR, design, Btu/kWh HHV 8,240 9,030 8,600 8,230 NPHR, achieved, Btu/kWh HHV 2 8,240 8,600 - Adjusted for HRSG 9,100 - Adjusted for gas/gas heat 8,230 feedwater heaters exchanger ASU Pressure, psi 145 72.5 145 145

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies

Table 3-3. Coal-Based IGCC Demonstration Plants (Continued)1

Project Nuon Power Wabash 3 TECO Polk County 4 Elcogas 5

Nitrogen Usage Syngas Saturator Vented CTG NOx Control Syngas Saturator

NOx Control Saturation and N2 dilution Saturation + steam injection N2 dilution to combustors Saturation and N2 dilution 3 NOx, 6% O2, mg/Nm 25 100 to 125 100 to 125 150 Slag Removal Lockhopper Continuous Lockhopper Lockhopper Recycle Gas Quench 50% of gas, to 1,650° F Some in second stage None 67% of gas, to 1,475° F Integration Water/steam Yes Yes Yes Yes

N2 Side ASU/CTG Yes No Yes Yes Air Side ASU/CTG Yes No No Yes Add Air Compressor Yes Yes Yes No Gas Cleanup Particulate Removal Cyclone/Ceramic candle filter Sintered metal candle filter Water wash Ceramic candle filter Chloride Removal Water scrubbing Water scrubbing Water scrubbing Water scrubbing COS Hydrolysis Yes Yes Retrofit in 1999 Yes AGR Process Sulfinol MDEA MDEA MDEA

Sulfur Recovery Claus + SCOT TGR Claus + Tail Gas Recycle H2SO4 Plant Claus + Tail Gas Recycle 3 SO2, 6% O2, mg/Nm 35 40 40 25 1 Information taken from “Operating Experience and Improvement Opportunities for Coal-Based IGCC Plants,” Holt, Neville from Science Reviews – Materials at High Temperatures, Spring 2003. Additional footnotes are by Black & Veatch. 2 Achieved NPHR (net plant heat rate) values are instantaneous values from performance testing. Long-term annual average heat rates vary with degradation and dispatch profile. 3 Wabash NPO (net plant output) and NPHR reported as 261 MW and 8,600 Btu/kWh in “The Wabash River Coal Gasification Repowering Project, an Update,” US DOE, September 2000. 4 TECO NPO and NPHR reported as 250 MW and 9,650 Btu/kWh in “Tampa Electric Integrated Gasification Combined Cycle Project,” US DOE, June 2004. 5 Based on ISO conditions. Site-specific design NPO was 283 MW, with probable further derate due to higher ASU auxiliary load.

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update 3.0 IGCC Technologies

Figure 3-6 depicts potential areas of integration. The European plants have been highly integrated, partly in response to higher fuel prices, while the US plants have been less integrated. Both the Nuon Power Buggenum plant in The Netherlands, and the Elcogas Puertollano plant in Spain, experienced operating difficulties as a result of the highly integrated design; however, most of these issues have been resolved. It is generally agreed within the industry that such high levels of integration as originally designed into the European plants should be avoided in the future. The operation of these four commercial coal fueled IGCC plants has adequately demonstrated capacity, efficiency, and environmental performance, but uncertainty remains regarding availability, reliability, and cost. The complexity and the relative immaturity of the IGCC process increase opportunities for deficiencies in design, vendor- supplied equipment, construction, operation, and maintenance. The high risks of cost overruns and low availability have presented obstacles to the development of coal fueled IGCC projects. At present, there are several coal-based IGCC projects being developed in the United States that have or expect to receive subsidies. These projects are discussed in Section 4.3.

Figure 3-6. Potential Areas for Integration

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3.6 Fuel Characteristics Impact on Gasifier Selection There are three general coal feedstocks typically considered for IGCC projects: Appalachian, Illinois, and PRB. Petcoke is a fourth solid fuel feedstock that is frequently considered for IGCC applications. Petcoke may be a lower cost fuel, but it is not as readily obtainable as coal. Historically, anthracite and lignite coals have not been seriously evaluated for IGCC projects, nor have waste coals such as gob (coal mine waste) and culm (waste produced when anthracite is mined and prepared for market, primarily rock and some coal). Coal-based operating experience has been focused almost exclusively on bituminous coals (e.g., Pittsburgh No. 8 and Illinois No. 6), and there is also extensive experience with petcoke. Subbituminous (i.e., PRB) coals that have been tested have only been gasified in large quantities in the Dow Plaquemine, Louisiana Gasification Plant, which used what is now COP gasification technology. Because of the nature of the US coal market and the abundance of PRB coal, there is strong interest in using it for IGCC applications. The high moisture content in PRB coal is reduced to 2 to 5 percent (by weight) during milling/drying in the Shell gasification process so that there is minimal impact on gasifier performance. The mill is swept with hot nitrogen or flue gas from combusted syngas. The dried, pulverized coal is separated from wet gas and conveyed with dry nitrogen to an elevated silo; then it is sent to a lockhopper, where it is pressurized above the gasifier operating pressure and sent to a feed bin; and finally, it is sent to the gasifier. After drying, the coal is kept under a nitrogen atmosphere to prevent fires until it is inside the gasifier. In the COP and GE gasification processes, the high inherent moisture content in PRB coal approximately doubles the total water content in the coal slurry per pound of dry coal to the gasifier. Vaporizing all of this water requires the combustion of more than

10 percent of the carbon in the coal to CO2, which reduces gasifier efficiency. In the COP gasification process, a portion of the coal slurry is injected into the hot raw gas from the first stage, where the coal is partially oxidized. This second-stage quench partially gasifies the injected coal. The unreacted, dry coal is filtered out of the gas and recycled to the first stage. This dry recycle step improves gasifier efficiency for PRB coal relative to the GE gasification process, but the COP gasification process is less efficient and more expensive than the Shell gasification process for PRB coal. In the GE gasification process, all of the inherent water in the coal and the liquid

water in the slurry must be evaporated in the gasifier by combusting more CO to CO2, which results in a lower cold gas efficiency than the COP and Shell gasification processes. Therefore, the GE gasification process has not been considered economical for PRB coal; however, GE is developing technology for the gasification of PRB coal.

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To select the design coal for gasification equipment, a fuel supply analysis is required. Coal moisture, ash, and sulfur content determine the size of the coal handling, coal milling (and drying for Shell), gasifiers, slag handling, AGR, sulfur recovery unit (SRU), and ASU. If a coal is used that exceeds the design values for coal moisture, ash, or sulfur, the syngas production capacity will be less than the design capacity. In this case, natural gas could be co-fired with the syngas to attain full output from the CTGs, and/or natural gas could be duct fired in the HRSGs to attain full output from the STG. A Shell gasifier can operate on any of the three general coal feedstocks. One design option is to size the syngas production components according to the worst-case fuel properties. This will result in additional capital cost, but will allow the plant to achieve roughly the same net plant output on syngas when operating on any of the fuels. A second option is to minimize the capital expense; some examples of this include designing for a Pittsburgh No. 8 fuel and either derating if other fuels are used or co- firing natural gas with the syngas.

3.7 IGCC Performance and Emissions Considerations IGCC net power output decreases with increasing ambient temperature, but this reduction is less than that of an NGCC plant. The IGCC plant auxiliary power consumption increases slightly with the ambient temperature for ASU air compression and cooling tower fans, but this is offset by higher combustion turbine output.

The CO and NOx emissions estimates were based on CTGs firing syngas with nitrogen dilution, but without an SCR system or CO oxidation catalyst in the HRSG: • 25 ppmvd CO in the CTG exhaust gas.

• 25 ppmvd NOx (at 15 percent by volume O2) in the CTG exhaust gas.

The SO2 emissions estimate was based on a 25 ppm molar concentration of sulfur

as H2S and COS in the syngas. Sulfur removal efficiencies of greater than 99 percent are achievable for an IGCC plant processing high sulfur coal or petcoke, depending on the solvent selected. Flaring during startups, shutdowns, and upsets can result in significant

SO2 emissions. Sour gas flaring during upsets cannot be eliminated, but can be minimized by appropriate process design and operating procedures. Syngas will flow through sulfur impregnated carbon, which is estimated to lower the mercury concentration below 5 ppb by weight. Up to 40 percent of the mercury in the coal may be removed upstream of the sulfur impregnated carbon by scrubbing, which would reduce the mercury concentration at the inlet of the sulfur impregnated carbon to 30 to 42 ppb by weight. Eastman Chemical Company’s coal gasification plant has used sulfur impregnated carbon beds for mercury removal since its startup in 1993and reports 90 to 95 percent mercury removal with a bed life of 18 to 24 months.

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The addition of SCR to IGCC will increase the potential of fouling in the HRSG. The potential for fouling is related to the quantity of sulfur in the syngas, the associated temperature of the syngas, and catalyst performance.

For combined cycle applications using sulfur-containing fuels, NH3 injection (SCR operation) should be limited to temperatures below 660° to 700° F to minimize the

conversion of SO2 to sulfur trioxide (SO3). SO3 in the presence of NH3 forms ammonium sulfate and ammonium bisulfate salts. The temperature at which precipitation of these

salts occurs from the flue gas is dependent on the relative concentration of NH3 and SO3 in the flue gas; as the NH3 concentration increases, so does the ammonium bisulfate temperature of precipitation. Ammonium bisulfate is a sticky substance that can deposit on catalysts, air heater baskets, HRSGs, and other downstream equipment. These particles of ammonium sulfate and bisulfate could foul the micropore structure of the catalyst, which would limit catalyst reactivity.

3.8 Gasification Wastewater Treatment There are two general categories of plant wastewater: • Streams that contain metals from the as-received coal, referred to as gasification wastewater streams. • Streams that do not contain these metals, referred to as balance-of-plant wastewater streams, including the following: − Water pretreatment sludge. − Reject water from the selected cycle makeup treatment process. − Plant and equipment drain water. − Sanitary wastewater. − Cooling water blowdown. − Uncontaminated site runoff. The gasification wastewater streams will be combined and treated separately from the balance-of-plant wastewater streams. Accurate specification of the process wastewater composition has been a problem on other operating gasification plants because of the wide variation in coal composition. The wastewater treatment design should accommodate variations in wastewater composition. There are three basic options for treating gasification wastewater streams: 1. Open Discharge Concept, which consists of metals precipitation, followed by biological treatment to produce an effluent suitable for discharge. 2. Zero Liquid Discharge (ZLD) Concept, which consists of lime softening, followed by evaporation and crystallization to produce a solid salt for landfill disposal.

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3. Discharge to a municipal sewage treatment facility or other receiving stream. This option is generally considered impractical, because the coal gasification wastewater exceeds typical pretreatment limitations. Biological treatment of the gasification wastewater can be problematic, because the diverse contaminants are believed to be sufficiently variable so that the operation would be unreliable, which could result in violations of expected permit requirements. The open discharge system would cost approximately the same as the ZLD option and is not a proven technology in this application. The operating costs are equivalent between ZLD and open discharge systems. However, ZLD requires additional LP steam, which could otherwise be used to generate an additional 2 to 5 MW of electricity.

3.9 Acid Gas Removal

Sulfur in coal is converted to H2S and COS during gasification. The molar ratio

of H2S to COS in the raw syngas from the gasifier varies according to the gasifier type, from approximately 13 to 1 for the Shell gasifier to 26 to 1 for the COP and GE gasifiers. The resulting syngas is treated to meet combustion turbine fuel and air emissions permit requirements. The requirement is for total sulfur in the clean syngas to be less than

25 ppm by weight, which is equivalent to 15 ppm by mole of COS and H2S. A

combination of COS hydrolysis to H2S followed by H2S absorption in solvent is used to

remove COS and H2S from the syngas. A discussion follows of the advantages and disadvantages of Selexol and methyl diethanol amine (MDEA) solvents for this service. The two primary solvents considered for IGCC AGR are Selexol and MDEA. Selexol solvent is a mixture of dimethyl ethers of polyethylene glycol,

CH3(CH2CH2O)nCH3, where n is between 3 and 9. Selexol is a physical solvent. Its

capacity to absorb sulfur compounds (including H2S) and to absorb CO2 increases with increasing pressure and decreasing temperature. The Cool Water coal IGCC demonstration plant used Selexol AGR. The Sarlux oil IGCC plant has been operating for more than 7 years with Selexol AGR. The Sarlux Selexol AGR uses propane refrigeration to cool the solvent to 32° F. The Coffeyville

Coke Gasification to Fertilizer Plant also uses Selexol to selectively remove H2S-COS

and CO2 from hydrogen. This plant has been operating for more than 7 years and uses

NH3 refrigeration to cool the solvent to 10° F. Selexol removes water from the syngas, resulting in a treated syngas water vapor concentration of approximately 50 ppm by mole. Rich Selexol solvent is regenerated by lowering the solvent pressure, which flashes absorbed gases, and by stripping using LP steam.

MDEA, (HOC2H4)2NCH3, is a chemical solvent, specifically a selective amine

used to remove H2S, while leaving most of the CO2 in the syngas. MDEA forms a

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chemical bond with H2S and CO2. MDEA’s performance is nearly independent of operating pressure. Typical absorber operating temperatures with amines are between

80° and 120° F. Lower absorber operating temperatures increase both H2S solubility and

selectivity over CO2. MDEA has been successfully used for the past 9 to 12 years at the Polk, Puertollano, and Wabash IGCC plants. MDEA is used in an aqueous solution of 40 to 50 percent by weight. MDEA treated syngas will be saturated with water at the MDEA absorber operating pressure. The MDEA treated syngas water vapor concentration is approximately 0.11 percent by mole in Shell syngas at 500 psia. Rich MDEA solvent is regenerated by stripping using LP steam. Heat stable salts (formates, acetates, oxylates, and thiosulfates) are formed by the reaction of syngas constituents with the aqueous MDEA solution. CO reacts with OH- to produce HCOO- (formate). Formate formation

increases with CO partial pressure. HCN and NH3 also degrade MDEA. These heat stable salts result from greatly increased corrosion. An expensive slipstream ion exchange unit is required to remove heat stable salts. Key parameters for differentiating the performance of Selexol and MDEA are listed in Table 3-4 for each of the gasification technologies:

Table 3-4. Syngas Characteristics Exiting the Acid Gas Absorber

Gasification Pressure, CO2, CO, Technology psia %mole %mole COP 575 12.2 52.6 GE 685 15.8 43.5 Shell 500 2.2 61.2

The higher absorber operating pressures and higher syngas CO2 concentrations for the GE and COP gasification processes favor the use of Selexol. The higher operating pressures allow more flashing of the syngas to lower the CO2 concentration in the solvent prior to the solvent stripping column. The solvent circulation rate would be lower for Selexol than for MDEA for all of the gasification technologies. This leads to lower capital and operating costs versus MDEA solvent. Upstream COS hydrolysis is required for both Selexol and MDEA.

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4.0 Gasification Participants and Potential Projects

Growing environmental concerns, along with recent changes in the gasification industry, appear to have spurred interest in coal-based IGCC applications among US energy companies. Major industry participants such as American Electric Power (AEP) and Duke Energy (formerly Cinergy) are developing IGCC projects. In addition, numerous smaller companies are pursuing IGCC using state and federal grants. Three coal fueled IGCC projects are currently under construction worldwide. Foundations for fuel storage buildings are being built at the 600 MW Global Energy plant in Lima, Ohio. MHI is building a 250 MW demonstration plant for its air-blown IGCC technology in Japan. OUC and Southern Company are building a 285 MW demonstration plant for the air-blown KBR TRIG process.

4.1 Key Participants in IGCC In addition to the gasification technology suppliers, there are several other critical technology suppliers for an IGCC project.

4.1.1 Combustion Turbine Vendors GE, SPG, and MHI have CTGs capable of operating in IGCC plants. Table 4-1 provides recent supplier syngas performance estimates for GE 7FB, SPG SGT6-5000F, and MHI 501F CTGs. GE has indicated that it will focus on the 7FB for IGCC applications.

Table 4-1. CTG Syngas Performance Estimates

Syngas Commercial ISO Heat Rate, Model Status Output, MW Btu/kWh (LHV) GE 7FB Available 232 8,360 MHI 501F Available 197 8,594 SPG SGT6-5000F Available 232 8,650

GE CTGs have more than 600,000 hours of syngas operating experience; the GE CTGs firing syngas are listed in Table 4-2.

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Table 4-2. GE CTG Syngas Experience

Size, CTG Syngas Start Owner - Site Country MW Feedstock Model Date Cool Water USA 120 Coal 7E May 1984 PSI/Global - Wabash USA 260 Coal/Petcoke 7FA Nov. 1995 TECO - Polk County USA 250 Coal/Petcoke 7FA Sept. 1996 Frontier Refining USA 40 Petcoke and 6B Sept. 1996 (El Dorado Refinery) Waste Oil SUV - Vresova Czech 350 Coal 2x9E Dec. 1996 Republic Schwarze-Pumpe Germany 40 Lignite 6B Sept. 1996 Shell Pernis Refinery Netherlands 120 Residual Oil 2x6B Nov. 1997 Delaware City USA 180 Fluid Coke 2x6FA Aug. 2000 Refinery Sarlux/Sara Refinery Italy 550 Visbreaker Tar 3x9E Oct. 2000 ExxonMobil Singapore 180 Cracked Tar 2x6FA Mar. 2001

SPG has more than 300,000 hours of syngas operating experience; the SPG CTGs firing syngas are listed in Table 4-3. The bulk of SPG IGCC experience is with CTGs developed by SPG (e.g., V94.2, V94.3). The Westinghouse large-scale CTG experience is limited to one installation of two 501D5 machines for Dow Chemical. MHI is evaluating its interest in actively developing and marketing CTGs for IGCC applications. Additional data will likely be available in the near future. MHI supplied the 701F CTG for the 342 MW 1x1 Negishi IGCC plant in Japan. This project began commercial operation in June 2003 and operates on residual oil. Negishi has a

NOx limit of 2.6 ppm (corrected to 16 percent O2), with an SCR removal rate exceeding 90 percent. While both GE and SPG offer several models of CTGs for IGCC applications, it is expected that the next (second) generation of large-scale commercial plants will be based upon enhanced “F” class machines. It is anticipated that third-generation IGCC plants will incorporate advanced “G” and “H” class machines.

4.1.2 Steam Turbine and HRSG Vendors The HRSG and STG do not require modifications for use in IGCC applications; thus, all current suppliers in the combined cycle market would also be likely candidates for IGCC applications.

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Table 4-3. SPG CTG Syngas Experience

Size, CTG Syngas Start Company Country MW Feedstock Model Date Hörde Steelworks Germany 8 Blast-furnace VM5 1960 Handan Iron & Steel China gas 2000 US Steel Corp. USA 20 Blast-furnace 201 1960 gas STEAG/Kellermann Germany 163 V93 1972 Dow LGTI USA 160 Coal 2x501D5 1987 Plaquemine Nuon Power Netherlands 250 Coal and V94.2 Natural gas Buggenum BV biomass 1993, Syngas 1994/1995 HRL Australia 10 Lignite Typhoon 1996 Sydkraft Sweden 6 Wood Typhoon 1996-2000 Elcogas Spain 283 Coal and V94.3 Natural gas Puertollano petcoke 1996, Syngas 1997/1998 ISAB Energy Italy 500 Asphalt 2xV94.2K Oil 1998, Syngas 1999 ELETTRA GLT Italy 180 Steel making V94.2K 2000 recovery gas ARBRE Energy UK 8 Biomass Typhoon 2002 EniPower Italy 250 Heavy oil V94.2K 2005

4.1.3 ASU Vendors ASU technology is commercially available and requires minor optimization for use in an IGCC plant. Currently, the maximum single train size in operation is 3,500 tpd (however, Air Liquide is building a 3,900 tpd ASU in Canada that will have a single cold box and two air compressors). This generally supports a single “F” class CTG train. Major ASU vendors include the following: • Air Liquide • Air Products • BOC • Praxair Conventional ASU technology relies on cryogenic distillation to separate oxygen. This is a mature, proven technology in a growing market. The capital cost of an ASU is generally about 10 percent of the total EPC cost of an IGCC plant. Perhaps more

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important than the initial capital investment, an ASU consumes approximately 15 to 22 percent of the IGCC gross output. Currently, there is ongoing research and development into a ceramic membrane to replace conventional ASUs. Current projections indicate a potential savings in both capital cost and power consumption of approximately 35 percent, when compared to the conventional cryogenic ASU. The US DOE is sponsoring a three-phase effort and has provided $90 million to a team led by Air Products. This team is entering the third phase of the program and has initiated construction of a small (5 tpd) pilot plant. At the present time, the expected scale-up timeline involves additional development through 2008, with a small-scale (25 tpd) pre-commercial demonstration facility. Commercial-scale use in an IGCC application is at least 10 years in the future.

4.2 Other Commercial Entrained Bed Gasification Experience GE water quench type gasifiers have been in commercial operation on coal or petcoke since 1983, producing syngas for chemical production. Two plants of note are the Eastman Chemical Plant in Kingsport, Tennessee, and the Ube Ammonia Plant in

Japan. The syngas from these two plants is used to produce acetyl chemicals and NH3, respectively. Kingsport has two gasifiers; one is normally operated and the other is a spare. Ube has four gasifiers; three are normally operated and one is a spare. Ube originally gasified crude oil, then switched to refinery residuals, then to coal, and has been gasifying a total of 1,650 tpd of petcoke since 1996. At Kingsport and Ube, an average syngas availability of 98 percent is achieved by rapid switchover to the spare gasifier (which is on hot standby) and the high level of resources (e.g., O&M) applied to the gasification process. The Eastman Kingsport plant has occasionally been referred to as an IGCC plant. This is incorrect because it produces no power; the Eastman plant produces syngas for chemical production, with no power generation. The economics of chemical production at the Eastman facility are different from the economics of the power market. As such, a fully redundant gasifier is warranted at the Eastman facility. Eastman has made gasification one of its focus areas, as evidenced by its formation of the Eastman Gasification Services Company.

4.3 Current Announced Electric Generation Industry Activity Major industry participants, such as AEP and Duke Energy (formerly Cinergy), are developing IGCC projects. In addition, numerous smaller companies are pursuing

June 2007 4-4 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 4.0 Gasification Participants and IGCC Technology Study – 2007 Update Potential Projects

gasification projects using state and federal grants. The more advanced, publicly discussed IGCC projects of which Black & Veatch is aware are shown in Table 4-4.9

Table 4-4. Announced IGCC Projects Currently in Development

Owner Size, MW Fuel Technology Location AEP 600 Bituminous GE OH AEP 600 Bituminous GE WV Duke/Cinergy 600 Bituminous GE IN Excelsior 600 Bituminous/PRB COP MN Southern & OUC 285 PRB KBR FL Global Energy 540 Petcoke COP IN Global Energy 600 Petcoke COP OH ERORA 557 Bituminous GE IL Energy Northwest 600 PRB/Petcoke NA WA NRG Northeast 630 PRB/Petcoke Shell NY TECO 630 Bituminous GE FL Mississippi Power Co. 700 Lignite KBR MS

Three coal fueled IGCC projects are currently under construction worldwide. Foundations for fuel storage buildings are being built to supply the proposed 600 MW Global Energy plant in Lima, Ohio. Construction of the main plant is scheduled to begin soon. MHI is building a 250 MW demonstration plant for its air-blown IGCC technology in Japan. Startup of this plant is scheduled for 2007, with the completion of the demonstration period by March 2010. Construction has started on the 285 MW OUC- Southern Company TRIG demonstration plant in Orlando, Florida. The eight projects described in the following subsections were selected based on their perceived stage of development and their applicability to IGCC projects. The data contained in the descriptions comes from publicly available sources. There is generally not enough data to describe the scope of work associated with the cost estimates provided, nor to compare them with the costs presented in this study. Several of the projects include data presented at the 2006 Gasification Technologies Conference held October 1 through 4 in Washington, DC.

9 According to a December 28, 2006, press release, AEP will delay its IGCC plant development to try to reduce the estimated capital cost to be within 20 percent of the market pricing of a “conventional coal fired power plant.”

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4.3.1 American Electric Power Company On August 31, 2004, AEP announced that it would build at least one baseload IGCC facility. AEP is the nation’s largest electricity generator and owns more than 38,000 MW of generating capacity. Coal and lignite provide approximately 27,000 MW

of this capacity. AEP anticipates future CO2 regulations and is considering building

IGCC plants that have the possibility of CO2 capture. AEP evaluated sites in its eastern territory and ultimately settled on three primary sites for an IGCC plant. The sites are Great Bend in Meigs County, Ohio, adjacent to its Mountaineer Plant in Mason County, West Virginia, and the Carrs site in Lewis County, Kentucky. On September 29, 2005, AEP announced that it had signed an agreement with GE Energy and Bechtel Corporation to develop the front end engineering design (FEED) for the Great Bend IGCC plant in Ohio. AEP expects that this preliminary engineering phase will be completed in November 2006. On August 17, 2006, AEP announced that it had signed a second agreement with GE Energy and Bechtel Corporation to proceed with the FEED for the proposed Mountaineer IGCC plant in West Virginia. The FEED process for the West Virginia project is expected to conclude in mid-December 2006. The proposed plants will have two GE radiant entrained flow gasifiers with two GE 7FB CTGs and a STG. The plants will use Selexol for sulfur removal, activated carbon for mercury capture, but will not include an SCR system. Provisions are being

made for the potential future addition of SCR, CO2 capture, and polygeneration. The plants will be fueled by Eastern coal and will use AEP’s coal-delivery infrastructure already in place. Transmission studies are under way for the three proposed sites and are expected to be completed in 2006. AEP’s Ohio operating company filed for cost recovery March 18, 2005, with the Public Utilities Commission of Ohio (PUCO) to build an IGCC plant at the Great Bend site. On April 10, 2006, PUCO approved AEP’s request to recover preconstruction costs, estimated to be $23.7 million, associated with the IGCC facility. Phase One cost recovery will include costs related to the company’s preconstruction costs or the costs incurred prior to AEP entering into an EPC contract. PUCO found that the costs of the IGCC plant are costs that AEP will incur to assist the company in meeting its “provider of last resort obligation” to all consumers in its certified territory. The filing estimated the expected cost of the 600 MW IGCC as $1.1 billion. AEP filed an application with the OPSB in March 2006 for a Certificate of Convenience and Necessity. AEP anticipates that the Ohio certificate will be issued in March 2007. In January 2006, AEP filed an application for a Certificate of Public Convenience and Necessity (CPCN) with the West Virginia Public Service Commission for approval of cost recovery for an IGCC plant in West Virginia. AEP expects a ruling

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on the West Virginia certificate in June 2007. AEP will file a rate case requesting cost recovery in West Virginia following completion of the FEED. Air permit applications were filed in both Ohio and West Virginia on October 2, 2006, and NPDES permit applications are expected to be submitted for both sites in 2007. On May 16, 2007, the Ohio Power Siting Board (OPSB) approved the site selection of the Great Bend IGCC plant; however, issues still remain with the cost recovery of the project. AEP announced that it will not consider the project unless ratepayers bear the risk of the project. In June 2007, AEP announced that the estimated cost for the West Virginia IGCC plant is $2.23 billion, or 72 percent greater than AEP’s previous estimates for the plant. AEP attributed the change to increased costs for steel and other construction materials, along with higher labor costs since its initial estimates were issued and stated that the IGCC plant will still cost 20 to 30 percent more than a standard coal-fired plant. If approved, the plant will likely cause electric rates in West Virginia to rise about 12 percent in order for the American Electric Power subsidiary to recoup its costs. AEP said it hopes to complete the plant, adjacent to the existing Mountaineer Plant, by mid-2012.

4.3.2 Duke Energy (Cinergy/PSI and Vectren) On October 26, 2004, PSI Energy, Cinergy’s Indiana subsidiary, signed a letter of intent with GE and Bechtel Corporation to study the feasibility of an IGCC plant. This plant is the first one announced under the GE/Bechtel alliance. In January 2005, a technical services agreement was signed with GE/Bechtel to provide indicative costs, performance, and schedule. Several sites in Indiana were investigated, but the preferred site is PSI’s 160 MW Edwardsport coal fired generating plant in Knox County. The scope of work was completed in August 2005, and the site was confirmed. On September 21, 2005, Vectren Corp. and Cinergy/PSI announced that they will work together on plans for a clean coal power plant that would generate about 600 MW of electrical capacity. On February 13, 2006, an agreement was signed with GE and Bechtel to begin FEED, which is expected to be completed by early to mid-2007. On March 10, 2006, Cinergy and Duke Energy merged and retained the Duke Energy name. As of October 2006, the team had provided comments on process flow diagrams and piping and instrumentation diagrams (P&IDs) and was ready to begin cost estimating. On June 15, 2006, Duke Energy Indiana (DEI) submitted an Integrated Resource Plan (IRP) to the Indiana Utility Regulatory Commission (IURC). It stated that its least- cost expansion plan included a 50 or 80 percent share of an IGCC at Edwardsport in the 2011 to 2014 time frame. In September 2006, DEI reached an agreement with the two state agencies for cost recovery of the FEED study. Duke and the participating

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companies can recover up to $20 million if the plant is constructed, and up to $10 million if not. In September 2006, DEI and Vectren filed a joint petition with the IURC for a Certificate of Public Convenience and Necessity (CPCN) to construct the Edwardsport IGCC facility. They anticipate approval in the third quarter of 2007. DEI reportedly expects to spend between $1.6 and 2.1 billion on the nominal 630 MW plant. An air permit application was filed with the Indiana Department of Environmental Management on August 18, 2006. With the planned retirement of the existing

Edwardsport PC unit, there are net reductions in SO2 and NOx. No Prevention of Significant Deterioration (PSD) or Best Available Control Technology (BACT) analysis is required for these pollutants. The application is based upon worst-case coal data and

does not include SCR. However, DEI may install SCR if it proves practical. CO2 capture is not included in the current scope. DEI anticipates receiving the air permit in the third quarter of 2007. DEI is pursuing funding at the county, state, and federal levels. Knox County approved a 10 year property tax abatement and a 45 percent tax incremental financing district on April 11, 2006. Local and state incentives include the Indiana Senate Bill (IN SB) 29, which would provide timely recovery of the IGCC construction and operation costs, and the IN SB 378, which would provide an incentive tax credit of 10 percent of the project costs for the first $500 million, and 5 percent of the remaining costs. DEI submitted an application for Federal Tax Credit under Section 48A of the Energy Policy Act of 2005. It stated that it needs federal tax incentives to move this project forward. On December 1, 2006, the IGCC project was selected for the Federal Tax Credit, eligible for $133.5 million. Assuming that required permits and approvals are granted, DEI projects a start of construction in the fourth quarter of 2007, with commercial operation in the second quarter of 2011. In May 2007 DEI issued a project update. The FEED study was completed in March 2007 and the report submitted to the IURC in April 2007. The current cost estimate is $1.985 billion and the project contracting approach will not be EPC. DEI will manage a blend of cost reimbursable, target cost, and lump sum contracts. The air permit application was paused, but was expected to be restarted in mid May with a permit issued late in 2007. DEI also expects the CPCN in late 2007.There will be net reductions in SO2 and NOx from the site, therefore no PSD or BACT analysis is required for these pollutants. They estimate a 47 month schedule from full notice to proceed to ssubstantial completion.

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4.3.3 Excelsior Energy, Inc. On June 10, 2004, COP and Excelsior Energy Inc., signed a development and technology licensing agreement for an IGCC plant utilizing COP E-Gas technology. Excelsior’s Mesaba Energy Project will be located in northeastern Minnesota in an area known as the Iron Range. Excelsior has been engaged in the development of this project since 2001. The Mesaba Energy Project has received broad-based support from state government, labor, business, and political leaders within Minnesota and in Washington, DC. Supportive legislation passed in Minnesota provides the project an exemption from the certificate of need process for initial and future generation and transmission. On October 26, 2004, the US DOE announced that the Excelsior Energy team had been selected to receive a $36 million award as part of the 2002 CCPI. At that time, the estimated total cost for the coal-based demonstration project was reported to be $1.18 billion (the basis for this number is unclear). This project was one of two selected to demonstrate advanced power generation systems using IGCC technology. Excelsior Energy has also been awarded $10 million in funding from a Minnesota renewable energy account. On August 29, 2005, Excelsior announced that it had selected a preferred and an alternate site. The preferred site is in Itasca County, Minnesota. Approval of site selection must be obtained from the Minnesota Public Utilities Commission (MPUC). Excelsior has secured an option for more than 1,000 acres. The project cost for a single 600 MW 2-on-1 IGCC facility was reported as $1.5 billion, with up to 1,000 construction jobs over the 4 year construction period. Excelsior Energy will own the project, and COP will license the technology and operate the project. Power will be sold to Northern States Power, an Xcel Energy company. Fluor has been selected as the EPC contractor, and SPG is also a member of the team. In an October 2005 presentation, the total project cost was identified as $1.97 billion (the basis for this number is unclear, but likely includes O&M and fuel for the demonstration period), with the project expected to be operational in 2012, producing up to 600 MW (net) of electricity. Unique features of the project include the first application of the COP full-slurry quench process and integration between the ASU and the CTG. The project is expected to be able to utilize bituminous and subbituminous coals as well as petcoke blends. The project includes a 12 month demonstration phase. Information available in October 2006 indicates a heat rate between 9,033 and 9,500 Btu/kWh, depending upon the fuel, with a net output of 606 MW. The plant includes a spare

June 2007 4-9 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 4.0 Gasification Participants and IGCC Technology Study – 2007 Update Potential Projects gasifier and is described as carbon capture adaptable. The design does not include an SCR system. On October 5, 2005, the US DOE announced its intent to prepare an Environmental Impact Statement (EIS). Excelsior submitted a Joint Permit Application to the MPUC in June 2006. Also in June, it submitted air and National Pollutant Discharge Elimination System (NPDES) permit applications to the Minnesota Pollution Control Agency, and a water appropriations application to the Department of Natural Resources. Excelsior anticipated the permits being issued in the fourth quarter of 2007, followed by financial close on the project in the first quarter of 2008. In October 2006, Excelsior requested that the MPUC order Xcel to enter into a 25 year PPA. The Transmission study was completed by MISO in January 2007, confirming that the Project output is deliverable within the regional MISO grid with $70 million of upgrades to existing system. Fluor was released to begin detailed engineering in February 2007. In March 2007, Excelsior reached an agreement with COP for a Process Design Package to be completed by the end of 2007, with Fluor completing the FEED in 2008. On April 16, 2007, a judge’s report advised MPUC to deny the approval of the PPA, stating that the plant was not an innovative energy project nor the least-cost option for electrical production. This decision could terminate the project. In May 2007, Excelsior requested a schedule change based on the the Draft EIS being issued by June 30, 2007.

4.3.4 Southern Company and Orlando Utilities Commission In 2004, Secretary of Energy Spencer Abraham announced a $235 million grant from the US DOE for the development of an IGCC project led by Southern Company. The plant will be located near Orlando at OUC’s Stanton Energy Center. The total cost for the coal-based demonstration project is reported to be $792 million (the basis for this number is unclear, but it has been stated that this would include O&M and fuel for 4 years of demonstration), of which the US DOE will contribute $235 million as the federal cost share. The partnership of Southern with OUC and KBR will contribute $322 million. This project, along with the Excelsior project, was one of two selected to demonstrate advanced power generation systems IGCC technology. Two air-blown, coal-based transport gasifiers will be designed and constructed for a 285 MW (net) baseloaded, KBR TRIG combined cycle refueling application. The combined cycle will consist of a modified GE 7FA CTG, HRSG, and STG and is estimated to have a design heat rate of 8,400 Btu/kWh. To serve peaking needs, output can be increased to 311 MW (net) by firing natural gas in the HRSG. Using two gasifiers

June 2007 4-10 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 4.0 Gasification Participants and IGCC Technology Study – 2007 Update Potential Projects for the demonstration plant will limit the extent of scale-up required from the PSDF pilot plant. The plant will be 100 percent coal fired using low sulfur PRB subbituminous coal.

The HRSG will include SCR for NOx control. The IGCC is broken into two projects, with OUC owning the 1-on-1 combined cycle and a joint ownership of the gasification island (65 percent Southern Company, 35 percent OUC). OUC’s Need for Power Application was approved by the Florida Public Service Commission on May 24, 2006. In February 2006, Southern Company formally signed the cooperative agreement for the project with the US DOE. Initial funding of $13.8 million will support project activities through March 2007, when the FEED is expected to be complete. Detailed design and equipment procurement was scheduled to begin in April 2007. Operation is slated for June 2010. In January 2007, the US DOE issued the final EIS for the project. The US DOE issued the NEPA Record of Decision in April 2007, clearing the way for project construction. Detailed design and equipment procurement began in April 2007, with site construction to begin in December 2007. The commercial operation date for the project is set for 2010, with demonstrations complete in 2014. In May 2007 NETL provided a project update. Current cost projection is $844 million, with the DOE share at $294 million.

4.3.5 Global Energy Projects Global Energy, which owns 50 percent of the Wabash Gasification Plant, has had two IGCC projects under development for some time. The first was to be a 540 MW US DOE-funded Clean Coal Technology Project called Kentucky Pioneer Energy. The second project would be very similar to Kentucky Pioneer, only without any US DOE funding; it was to be the 600 MW Lima Energy plant in Lima, Ohio. Both projects were originally designed with British Gas Lurgi fixed bed gasifier technology (instead of entrained flow technology), and both have been delayed. Lima Energy plans to build an IGCC power station at the former Lima Locomotive Works on South Main Street. The plan, announced in 1999, has been delayed repeatedly, first by permit issues, then from an inability to sign offtake agreements for the electricity from the 540 MW plant, and more recently because of financing concerns related to the initial fixed bed gasification technology (the new design would incorporate entrained flow technology). The project was reported to cost $575 million (the basis for this number is unclear). Lima Energy hopes to raise $512 million through Ohio Air Quality Development Authority bonds to finance construction.

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On September 18, 2004, Global Energy, Lima Energy’s parent company, announced that the company had finally sold all of its projected power output, ensuring a 20 year, $2.7 billion revenue stream. That, along with the financial backing for plant construction, was the key hurdle that needed to be cleared before construction could start. On November 22, 2004, the Ohio Power Siting Board approved Lima Energy’s request to change the gasifier technology listed on the permit from a slagging fixed bed to a COP slurry-fed entrained flow. Lima Energy asserted that financing would be more readily obtainable with the revised technology. In October 2005, Global Energy announced that it was beginning construction of a 600 MW IGCC facility in Lima, Ohio, with the fuel storage building. Industrial Construction Company, Inc., has been selected to construct the building, which will have a footprint of 100,000 square feet and will approach 100 feet in height, capable of storing 75,000 tons of fuel under its roof. Roberts & Schaefer Company is engineering the solid material handling scope of the facility and will serve as construction manager for this project. Construction officially began in November 2005. Gasification will convert solid petcoke feedstock into synthetic gas, which, after purification, will be both the fuel for the gas turbine power generation and the feedstock to produce synthetic gas products, such as hydrogen and synthetic natural gas. Construction will involve several hundred workers over 3 years. The commercial operation date of the IGCC facility is expected in late 2009. The cost estimate is $775 million. Permanent staffing will be in excess of 100, about half of which will be in operations. The project has all of its permits and approvals and has sold 100 percent of the electric power under long-term contract. The project has qualified for tax exempt bond financing as an Air Quality Facility under the Ohio Air Quality Development Authority. The facility will be designed and constructed under contract to Gasification Engineering Corporation (GEC), a Global Energy company. GEC will subcontract major engineering and construction management and will handle direct purchase of major equipment. In May 2007 a project update was issued by Lima Energy. Demolition and site prep is in progress and the fuel storage barn foundation is complete. Design engineering is 5 percent complete and the estimated cost is $1,200/kW. The project configuration includes will provide a nominal 600 MW of power plus SNG. It is based on four COP E- Gas gasifiers (3 plus 1 spare) and will include two GE 7FAs. The feedstock is 8,100 tpd of petcoke and the ASU is designed to provide 99.5 percent pure oxygen. Startup is projected in the fourth quarter of 2009.

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4.3.6 The ERORA Group, LLC In 2004, the ERORA Group began developing the Taylorville Energy Center, a 677 MW minemouth IGCC project in Illinois, based on GE technology. The reported project cost is $1.1 billion (the basis for this number is unclear), with a projected construction start in 2007 and a commercial operation date in 2010. Permits for the mine have been acquired, and the air permit application has been filed. The Illinois Clean Coal Review Board (CCRB) and the Illinois Department of Economic Opportunity awarded ERORA a $5.75 million grant for feasibility studies, as well as engineering and design studies. On April 5, 2005, Eastman Chemical Company and ERORA entered into an agreement to study the feasibility of chemicals co-production at the proposed IGCC facility. Initially envisioned as a PC facility in 2003, ERORA received a grant from the Illinois CCRB to study the potential for coal gasification. The co-production of chemicals from syngas has the potential to significantly improve the economics of power generation. The project is expected to be based on a 2-on-1 7FB combined cycle and

utilize Selexol. The project includes the option for potential future CO2 capture. The project is evaluating the co-production of synthetic natural gas. On January 9, 2006, Illinois Governor Rod R. Blagojevich announced $5 million in public-private support. The ERORA Group will receive $2.5 million for FEED work from the Illinois Department of Commerce and Economic Opportunity (DCEO), and another $2.5 million from the public-private Illinois Clean Coal Review Board. On January 23, 2006, ERORA signed a license agreement with GE Energy, authorizing the use of GE’s Radiant gasification technology for the project. GE has also been selected to provide the process design for the gasification portion of the facility and the power island. On July 11, 2006, Tenaska, Inc., entered into an agreement to purchase a 50 percent development-stage interest in the proposed Taylorville Energy Center. The agreement calls for Tenaska to jointly develop the remainder of the project with the ERORA Group. Tenaska also has an option to purchase the remaining 50 percent of the project’s equity. On October 10, 2006, the Illinois Finance Authority gave preliminary approval to $500 million of bonds for the Taylorville Energy Center. These would be the first under the state's $3 billion clean coal and energy program. Under the deal, $150 million of the bonds would be taxable and would carry Illinois' moral obligation pledge. The moral obligation pledge would require the governor to seek funds from the General Assembly if revenue from the project was insufficient to make debt service payments. The deal also calls for $350 million of tax-exempt, solid-waste disposal facilities bonds that would be subject to volume cap. The US government allocates a limited

June 2007 4-13 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 4.0 Gasification Participants and IGCC Technology Study – 2007 Update Potential Projects amount of volume cap to Illinois and other states each year, allowing them to issue tax- exempt bonds for private projects and uses. Tenaska is expected to seek final approval for the bonds in 2007 and begin construction in late 2007. No bond underwriters have yet been selected. Finance authority officials stressed that the project was still in the preliminary stages and faced many more steps before any bonds could be sold. Estimates as of June 2007 indicate a nominal net output of 630 MW and an estimated cost of $2 billion. On June 6, 2007, the Illinois EPA awarded an air permit allowing construction of the project to commence, pending finalization of commercial aspects of the project. There are a number of hurdles that remain, including approval of the Illinois Clean Coal Program Law that allows developers to enter into long-term, regulated cost-based contracts with large Illinois electric utilities. ERORA is developing a similar project in Henderson County, Kentucky, known as Cash Creek. An air quality permit application was declared complete March 29, 2007. A public hearing for Cash Creek is being held June 29, 2007.

4.3.7 Energy Northwest Energy Northwest has performed a feasibility study on IGCC for 300 to 600 MW of electricity to be installed in western Washington State. On July 27, 2005, the Board of Commissioners passed a resolution to proceed with the project development, starting with permitting. The approval is contingent upon permitting and execution of a power purchase agreement. On October 27, 2005, Energy Northwest announced the selection of the Port of Kalama for a proposed 600 MW IGCC complex, slated for initial operation in 2012. The agency’s Executive Board approved a 50 year lease for an 80 acre industrial site owned by the Port. The IGCC complex will produce its own syngas to fuel two 300 MW power plants: one owned by public power interests, the other under private financing and ownership. Construction of the complex, officially named the Pacific Mountain Energy Center, is expected to draw several hundred workers and create approximately 100 permanent jobs. The site provides adequate space for future expansion. The estimated design and procurement cost for the power complex is approximately $1.5 billion. The cost would include $35 million to make the facility compatible with potential future technologies to remove and capture CO2 from the feedstocks and allow sequestration of the CO2 in ancient lava flows nearly a mile underground, if and when it becomes commercially feasible. Energy Northwest issued a request for qualifications in March 2006, and expected to have an agreement with an EPC contractor by May of 2007, resulting in a commercial operation date of 2012.

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On September 12, 2006, Energy Northwest submitted an Application for Site Certification to the Washington State Energy Facility Site Evaluation Council (EFSEC) for the proposed Pacific Mountain Energy Center. EFSEC is the state lead agency for major energy facilities and will produce an EIS. A draft EIS was issued May 14, 2007. On May 8, 2007, Energy Northwest announced that it will slow the development of the Kalama project in response to a new Washington state law that sets enforceable limits

on CO2 emissions from electric power plants. Although the facility has set aside $35 million to modify the plant for future CO2 capture and sequestration, sequestration has not been proven on a commercial scale. Energy Northwest is waiting for clarification of the law.

4.3.8 NRG Northeast In December 2006, New York state conditionally awarded a PPA to NRG for building a 680 MW IGCC facility at NRG’s Huntley (New York) site. NRG has selected MHI IGCC technology for this plant. NRG is in the early stages of Phase 3, detailed development. It has applied for Federal Tax Credit under Section 48A of the Energy Policy Act of 2005. NRG recognizes that carbon is a serious issue with stakeholders in the Northeast, and is conducting capture and sequestration studies. The plant is scheduled to go on line in 2013. NRG had also explored IGCC projects in Delaware and Connecticut, but decided not to pursue those further.

4.3.9 Summary of Proposed Projects The development activities of the eight companies discussed in the previous subsections represent advances in the development of new IGCC plants within the United States. Entrained flow gasification technology has been selected by six of the companies. Southern Company and OUC are moving forward with the commercial demonstration of a transport bed gasifier. Energy Northwest has not selected a vendor at this stage, but all indications are that it will be a COP, GE, or Shell entrained flow gasification technology. All of the projects are in coastal or Midwestern locations, with elevations generally at 1,000 feet or less. The AEP, Duke, and ERORA projects are all based upon bituminous coal. The Global Energy Lima project is based upon petcoke. Excelsior Energy and Energy Northwest anticipate a blend of fuels that would include PRB coal with petcoke. The Southern Company/OUC project is based upon 100 percent PRB coal, but is a commercial demonstration project for a new gasification technology and the

June 2007 4-15 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 4.0 Gasification Participants and IGCC Technology Study – 2007 Update Potential Projects demonstration will not be complete until 2015. The fuel supply for the NRG Huntley IGCC Plant will be primarily coal, but could include petcoke or biomass.

June 2007 4-16 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 5.0 Performance and IGCC Technology Study – 2007 Update Emissions Estimates

5.0 Performance and Emissions Estimates

This section describes the process used to develop the initial IGCC options to be considered. Performance and emissions estimates for a nominal 600 MW greenfield plant for these configurations are provided.

5.1 Configurations In the initial screening, Black & Veatch developed performance estimates as well as capital and O&M cost estimates for six gasification technology and fuel combinations. Alliant Energy has determined, based upon availability and delivered price, that the mostly likely feedstocks for a new plant in its service territory are Illinois No. 6 and PRB coals. The intent of this evaluation was to focus on gasification technology differences; as such, differences among CTGs, HRSGs, and STGs were minimized to the extent practical. GE 7FB CTG performance was used. Performance and costs would be similar for the SPG SGT6-5000F and MHI 501F CTGs. Table 5-1 lists the differentiating aspects of the six scenarios. The two COP configurations differ between the PRB and Illinois No. 6 scenarios, because a third gasifier and syngas cooling train are required to handle the additional quantity of coal for the PRB scenario.

Table 5-1. IGCC Configuration Scenarios

GE - GE - Gasifier COP COP Quench HTHR Shell Shell Coal Type PRB Ill. No. 6 Ill. No. 6 Ill. No. 6 PRB Ill. No. 6 Gasifier Trains 3-33.3% 2-50% 4-33.3% 2-50% 2-50% 2-50% Spare Gasifier No No Yes No No No Syngas Cooling Trains 3-33% 2-50% 2-50% 2-50% 2-50% 2-50% AGR 1-100% 1-100% 1-100% 1-100% 1-100% 1-100% SRU 2-50% 2-50% 2-50% 2-50% 2-50% 2-50% ASU Cold Box Trains 2 2 2 2 1 1 ASU Compressors per Cold Box 1-100% 1-100% 1-100% 1-100% 2-50% 2-50%

Based on previous analyses discussed in Section 3.6, the GE gasification process was not considered further for PRB coal. Consequently, both of the GE configurations were designed for Illinois No. 6 coal. The GE Quench gasification technology readily lends itself to a spare gasification train, because the gasifier is inexpensive and there is no

June 2007 5-1 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 5.0 Performance and IGCC Technology Study – 2007 Update Emissions Estimates

expensive syngas cooler. For the purposes of this study, the GE Quench alternative contains a spare gasifier, resulting in higher availability. Alternatively, the GE Quench case could be evaluated without a spare, resulting in reduced capital costs and reduced availability. The Shell configurations for the PRB and Illinois No. 6 scenarios are virtually identical. It is feasible that the Shell scenarios could be designed with a single gasifier.

5.2 Performance Indicative performance estimates, developed by Black & Veatch, are presented in Tables 5-2 and 5-3 for IGCC operation and in Table 5-4 for operating only the combined cycle portion of the plant on natural gas (backup fuel). Actual performance data will vary with specific plant design characteristics, equipment conditions, and plant operation. The estimated IGCC performance is based on integrating the gasification heat recovery with

the combined cycle and nitrogen dilution for CTG NOx control. Air extraction from the CTGs would be 15 to 22 percent of the ASU air demand at a 59° F ambient temperature. Net power output decreases with increasing ambient temperature, but this reduction is less than that of a natural gas fired combined cycle plant. The reduction in CTG air compressor capacity resulting from increased ambient temperature can be compensated for by increased nitrogen injection, which results in constant CTG power output but increased auxiliary power consumption. Plant auxiliary power consumption also increases slightly with ambient temperature for the ASU air compression and cooling tower fans. Figure 5-1 illustrates how shaft torque, rather than ambient air temperature, limits the GE 7FA and 7FB CTG power output, when the reduction in CTG air compressor capacity is made up with increased water vapor in the syngas and or with additional nitrogen addition. The GE 7FB, the SPG SGT6-5000F, and the MHI 501F CTGs are expected to exhibit similar responses to ambient temperature.

5.3 Scenarios Selected for Additional Analysis The initial evaluation considered six gasifier supplier/technology and coal quality scenarios, as described in Section 5.1 and listed in Table 5-1. After reviewing the results of the screening (performance estimates in Table 5-2, capital cost estimates in Table 8-3, and O&M cost estimates in Table 8-4) and discussing the characteristics of each gasifier technology, Alliant Energy and Black & Veatch agreed to consider two scenarios in greater depth. The Shell PRB scenario was selected because it has the lowest capital cost and lowest heat rate option for PRB coal. The GE Quench scenario was selected to better evaluate the impact of a spare gasifier. In addition, the GE Quench has the lowest cost

June 2007 5-2 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 5.0 Performance and IGCC Technology Study – 2007 Update Emissions Estimates scenario, but has a higher heat rate than the other Illinois No. 6 options. The majority of the following sections focus on these two scenarios.

Figure 5-1. GE 7FA/7FB Output on Syngas10

10 From a presentation by Norman Shilling, GE Energy, at Electric Power 2007, May 2, 2007, in Chicago, Illinois.

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Table 5-2. IGCC Performance Estimates at 59° F Ambient Temperature

IGCC Configuration COP COP GE - Quench GE - HTHR Shell Shell Gasifiers 3-33.3% 2-50% 4-33.3% 2-50% 2-50% 2-50% Combined Cycle 2x1 2x1 2x1 2x1 2x1 2x1 CTG Model GE 7FB GE 7FB GE 7FB GE 7FB GE 7FB GE 7FB Air Separation Two Trains Two Trains Two Trains Two Trains 1 Cold Box 1 Cold Box 2-50% Air Comp 2-50% Air Comp Performance at 1,100 ft, 59° F Ambient, Clean and New Equipment Coal Type PRB Illinois No. 6 Illinois No. 6 Illinois No. 6 PRB Illinois No. 6 Coal, As-Received Heat Content, Btu/lb (HHV) 8,378 10,400 10,400 10,400 8,378 10,400 Moisture, percent wt 30 13 13 13 30 13 Ash, percent wt 5.1 10.6 10.6 10.6 5.1 10.6 Sulfur, percent wt 0.36 3.2 3.2 3.2 0.36 3.2 Quantity, stpd 8,145 6,097 6,361 6,361 7,189 5,685 Heat Input, MBtu/h (HHV) 5,687 5,284 5,513 5,513 5,019 4,927

Oxygen, stpd 100 percent O2 5,286 4,751 5,103 5,103 3,732 3,909 Cold Gas Efficiency, HHV, percent 72 77 74 74 83 82 CTG Heat Rate, Btu/kWh (LHV) 8,323 8,323 8,323 8,323 8,323 8,323 CTG(s) Gross Power, MW 452 452 452 452 452 452 STG Gross Power, MW 310 277 257 293 258 266 Syngas Expander Power, MW 0 0 5 3 0 0 Total Gross Power, MW 762 729 714 748 710 718 Auxiliary Power, MW 153 127 147 149 147 149 Net Power, MW 609 602 567 599 562 569 IGCC Net Heat Rate, Btu/kWh (HHV) 9,338 8,777 9,723 9,204 8,931 8,659 IGCC Energy Efficiency, HHV, percent 36.5 38.9 35.1 37.1 38.2 39.4

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Table 5-3. 2x1 7FB IGCC Performance Estimates - Various Ambient Temperatures

IGCC Configuration COP COP GE - Quench GE - HTHR Shell Shell Gasifiers 3-33.3% 2-50% 4-33.3% 2-50% 2-50% 2-50% Spare Gasifier No No Yes - 1 No No No Coal Type PRB Illinois No. 6 Illinois No. 6 Illinois No. 6 PRB Illinois No. 6 Performance at 1,100 ft, 59° F Ambient, Clean and New Equipment IGCC Net Heat Rate, Btu/kWh (HHV) 9,338 8,777 9,723 9,204 8,931 8,659 Net Power, MW 609 602 567 599 562 569 Performance at 20° F with Nonrecoverable Degradation (0.5% heat rate and 0.5% net power output degradation) IGCC Heat Rate, Btu/kWh (HHV) 9,221 8,666 9,604 9,096 8,810 8,548 IGCC Net Power Output, MW 617 610 574 606 570 576 Performance at 59° F with Nonrecoverable Degradation (0.5% heat rate and 0.5% net power output degradation) IGCC Heat Rate, Btu/kWh (HHV) 9,389 8,825 9,792 9,264 8,984 8,714 IGCC Net Power Output, MW 606 599 563 595 559 565 Performance at 80° F with Nonrecoverable Degradation (0.5% heat rate and 0.5% net power output degradation) IGCC Heat Rate, Btu/kWh (HHV) 9,660 9,083 10,097 9,537 9,266 8,985 IGCC Net Power Output, MW 589 582 546 578 542 548 Performance at 90° F with Nonrecoverable Degradation (0.5% heat rate and 0.5% net power output degradation) IGCC Heat Rate, Btu/kWh (HHV) 9,753 9,171 10,201 9,630 9,362 9,077 IGCC Net Power Output, MW 583 576 540 572 536 543

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Table 5-4. 2x1 7FB IGCC Performance Estimates for Natural Gas

Ambient Temp., °F 20 20 59 59 80 80 90 90 HRSG Duct Firing No Yes No Yes No Yes No Yes Performance at 1,100 ft, Clean and New Equipment Net Heat Rate, 7,331 7,635 7,328 7,701 7,371 7,763 7,431 7,815 Btu/kWh (HHV) Net Power, MW 530 633 488 593 463 569 449 557 Performance at 1,100 ft, Nonrecoverable Degradation (0.5% heat rate degradation and 0.5% net power output degradation) Heat Rate, 7,368 7,673 7,365 7,739 7,408 7,802 7,469 7,854 Btu/kWh (HHV) Net Power, MW 527 630 486 590 461 566 447 554

5.4 IGCC Plant Ramp Rates and Turndown Capability IGCC ramp rates and turndown capabilities are essentially equivalent for the three major entrained flow gasifier technologies (COP, GE, Shell). Gasifier ramp rates from minimum to maximum capacity are 1 to 3 percent of load per minute. Faster reductions in power generation can be achieved by temporarily flaring syngas. The gasifier load change capability for the Shell gasifier at the Nuon Power 250 MW IGGC plant (in Buggenum, The Netherlands) over small load intervals has been demonstrated at 5 percent load in 30 seconds and 2.5 percent load in 5 seconds. The GE gasifier will have a single feed injector (or burner). The Shell gasifier will have four feed injectors and can operate with only two feed injectors in service. Gasifier carbon conversion decreases as the gasifier load decreases as a result of the less efficient mixing of coal particles with oxygen in the gasifier. The maximum turndown capability for both the GE and Shell gasifiers is 50 percent of syngas output. The recommended operating load range for a single train IGCC plant (one GE or Shell gasifier with one “F” class CTG) is 60 to 100 percent.

5.5 Consumables and Byproducts Approximately 4,000 to 5,000 gpm of makeup water would be required for the IGCC plant, primarily for cooling tower makeup. The makeup water rate is lowest for the Shell dry feed coal gasification process and highest for the COP and GE slurry feed coal gasification processes. The estimated cooling tower duty is approximately 2,100 MBtu/hr, based on using low level heat from the gasification process in the

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combined cycle, which reduces cooling water duty. IGCC water use is typically 30 to 40 percent less than for PC or CFB technology. Gasification process wastewater will be treated by multiple effect evaporation and crystallization to produce a solid salt waste. Cooling tower blowdown and water treatment effluent will depend on the quality of the raw water supply. Sulfur and slag production estimates are provided in Table 5-5. Sulfur can be sold

for various chemical uses, the primary one being the production of H2SO4. The price of sulfur has been decreasing because of increasing supply, since high levels of sulfur removal from oil and gas processing are mandated to meet lower emissions limits, particularly for transportation fuels. Sulfur would be shipped by railcar from a Wisconsin IGCC plant location. The delivered price of sulfur may cover the cost of transportation. Sulfur is a yellow, inert (nonhazardous) material that can be used for fill material or landfilled for disposal. The small amount of sulfur produced from gasifying PRB coal, 42 lb/h for a nominal 600 MW IGCC, could be economically landfilled.

Table 5-5. TECO Polk County, Florida Slag Products

Carbon Percent of Size Range Content, Product Use Total Slag Mesh percent Slag for blasting grit, roofing granules, and 30 -40 to +12 0.5 cement. Fuel for PC boilers. Potential alternate is 50 -80 to +20 68 feedstock for activated carbon. Fines for recycle to gasifier or landfill. 20 -325 to +100 31 Potential alternate uses after pelletizing include PC boiler fuel and cement kiln fuel.

Slag is nonleachable and can be marketed locally for construction-related uses after samples are made available for testing by potential buyers. Slag can be used as aggregate in concrete filler in asphalt. Onsite slag storage will be needed for approximately 1 year of production. The carbon content of slag varies by gasifier type; Shell slag contains less than 1 percent carbon. Carbon conversion varies from 99.7+ percent for Shell gasifiers to 98 percent or less for GE gasifiers. Slag samples from Shell’s Deer Park gasifier were found to be nonleachable and classified as nonhazardous under the Resource Conservation and Recovery Act (RCRA).11 Shell fly slag,

11 Information taken from “An Environmental Overview of Integrated Gasification Combined Cycle Technology as Exemplified by the Shell Coal Gasification Process,” Davis, RJ and Salzman, DR; AWMA Kansas City, MO, June 1992.

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which is collected in the syngas filter and recycled with the coal back to the gasifier, contains 4 to 15 percent carbon. The TECO Polk County, Florida IGCC plant, which has a GE gasifier, was initially unable to market its slag because of its high chloride and carbon content. The source of the high chlorides and soot was carbon scrubber water. Modifications were made to segregate the carbon scrubber water from the slag and use higher quality water (condensate) for slag handling.12 The soot is recycled to the gasifier in the coal/coke slurry. A slag beneficiation process was installed and started up at the Polk County IGCC plant in 2001 to process the slag that had accumulated since startup.13 The beneficiation process separates slag into the three products, as described in Table 5-5.

5.6 Emissions Estimates Emissions estimates, developed by Black & Veatch, for a nominal 600 MW IGCC plant at an elevation of 1,100 feet are presented in Table 5-6 for Illinois No. 6 coal (for GE Quench and Shell gasification technologies) and for PRB coal (for Shell gasification technology) based on full load, steady-state conditions.

The CO and NOx emissions estimates are based on CTGs firing syngas with nitrogen dilution, but without SCR or CO oxidation catalyst in the HRSG. Space will be allowed for the addition of SCR and CO oxidation catalysts in the future. Reported emissions for the Polk County, Florida and Wabash, Indiana IGCC plants are presented in Table 5-7. 14,15

The estimated SO2 emissions for the future IGCC plants (shown in Table 5-6) are

lower than the actual SO2 reported emissions for the Polk County and Wabash plants presented in Table 5-7.

The SO2 emissions are lower because future IGCC plants are expected to recycle the tailgas from the Claus SRU to the syngas feed to the AGR unit. This eliminates the tailgas incinerator that is used at the Wabash IGCC plant. Because it is located near

major H2SO4 users, the Polk IGCC plant recovers its sulfur by producing H2SO4, which requires a vent stack. H2SO4 production is unlikely in most future IGCC plants.

12 Information taken from “Tampa Electric Polk Power Station IGCC Project Final Technical Report,” Hornick, MJ and McDaniel, JE; Tampa Electric Company for US DOE, August 2002. 13 Information taken from “Demonstration of a Beneficiation Technology for Texaco Gasifier Slag,” Geertsema, A; Groppo, J; and Price, C; Gasification Technologies Conference, San Francisco, October 2002. 14 Information taken from “Tampa Electric Polk Power Station Integrated Gasification Combined Cycle Project Final Technical Report,” Hornick, MJ and McDaniel, JE; Tampa Electric Company for US DOE, August 2002. 15 Information taken from “Wabash River Coal Gasification Repowering Project Final Technical Report,” Dowd, RA; Wabash River Energy Ltd for US DOE, August 2000.

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Elemental sulfur production using the Claus sulfur process will be the most common mode of sulfur recovery.

Table 5-6. IGCC Emissions Estimates for 600 MW Plant

Total Emissions at 100 Percent Load HRSG Stack Emissions Gasifier As-Received Coal Gas (ppmvd Type Type Coal Total, lb/h (lb/MBtu HHV) at 15% O2) GE Illinois 6 1,031,500 220

CO2 Shell Illinois 6 1,048,500 220 Shell PRB 1,082,500 215 GE Illinois 6 186 0.034 252 CO Shell Illinois 6 195 0.039 25 Shell PRB 205 0.041 25 GE Illinois 6 40 0.007 2.16

SO2 Shell Illinois 6 41 0.008 2.16 Shell PRB 42 0.008 2.06 GE Illinois 6 482 0.087 252

NOx Shell Illinois 6 490 0.099 25 Shell PRB 459 0.092 25 GE Illinois 6 72 0.011 Particulate1 Shell Illinois 6 72 0.013 Shell PRB 73 0.013 GE Illinois 6 0.01198 20 x 10-6 lb/MWh Mercury Shell Illinois 6 0.01138 20 x 10-6 lb/MWh (Hg) Shell PRB 0.01124 20 x 10-6 lb/MWh Byproduct GE Illinois 6 175 Liquid Shell Illinois 6 156 Sulfur, ltpd Shell PRB 22 Byproduct GE Illinois 6 675 Slag/Fly Shell Illinois 6 602 Ash, stpd Shell PRB 366 1 Particulate emissions include coal and slag/fly ash handling. 2 Better emissions rates may be achieved for CO and NOx, depending on the CTG vendor.

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Table 5-7. Reported IGCC Emissions for the Polk County, Florida and Wabash, Indiana IGCC Plants Total Emissions at 100 Percent Load Total, lb/h HRSG Estimated As-Received Stack Gas Emissions Emissions for 252 MW Coal (ppmvd at Type Plant Source Net (lb/MBtu HHV) 15% O2) Polk HRSG Stack 459,200 193

CO2 Wabash HRSG Stack 462,000 206 Wabash Incinerator3 Unavailable Unavailable Polk HRSG Stack Note 1 CO1 Wabash HRSG Stack Note 1 Wabash Incinerator3 0.2 Polk2 HRSG Stack 320 0.13 21

SO2 Wabash HRSG Stack 224 0.10 16 Incinerator3 35 Polk HRSG Stack 122 0.05 11 4 NOx Wabash HRSG Stack 141 0.06 15 Incinerator3 4 Polk HRSG Stack 9.3 0.004 Particulates Wabash HRSG Stack 13.5 0.006 Incinerator3 1 1 The Polk IGCC Final DOE Report stated that the HRSG stack CO annual testing averaged 7.2 lb/hr, but no operating rate was provided. The Polk IGCC Air Permit limits HRSG stack CO emissions to 99 lb/hr. The Wabash IGCC Final DOE Report stated the 1997 and 1998 CO emissions were 33.67 and 29.68 tons per year, respectively, which is an hourly average of 7.9 and 6.8 lb/hr, respectively. The Wabash Air Permit limits HRSG stack CO emissions to 21 ppmvd at 15 percent O2. The Polk and Wabash CO emissions rates of 7 to 8 lb/hr are less than 10 percent of the rates based on GE’s stated 25 ppmvd for CO in the exhaust gas of its 7FA CTGs firing syngas. 2 Polk IGCC emissions exclude the H2SO4 plant. 3 Wabash tailgas from the SRU is incinerated to convert residual H2S and COS to SO2. 4 Polk NOx in the CTG exhaust gas was lowered from 15 to 11 ppmvd at 15 percent O2 in 2003, by adding water vapor to the syngas to comply with the new, lower permit limit of 15 ppmvd at 15 percent O2.

Dry-low NOx (DLN) combustors are commonly used in natural gas fired CTGs; they produce exhaust gas NOx concentrations ranging from 9 to 15 ppmvd. DLN combustors are not suitable for syngas, because the high flame speed of the hydrogen in the syngas causes flame instability. CTG suppliers offer diffusion burners for syngas, which require syngas dilution for NOx control. Steam, water, CO2, and/or nitrogen can be

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used as syngas diluents and produce exhaust gas NOx concentrations of about 15 ppmvd.

GE indicates that it expects to achieve an exhaust gas NOx concentration of 10 ppmvd for syngas in the near future. However, if natural gas is fired in the diffusion combustor,

steam or water injection would be required for NOx control, and the expected NOx concentration in the exhaust gas would be 25 ppmvd. Exhaust gas NOx would increase to 42 ppmvd for oil firing. State air permits typically restrict oil firing to a limited number of hours per year and do not allow oil firing in the summer. These limitations, and the logistics of supplying large quantities of oil required for a plant of this size, make oil backup unattractive. The ASU produces a large volume of nitrogen that is suitable for syngas nitrogen dilution after compression. Nitrogen dilution is the most economical choice for GE 7FB CTGs, because this process injects nitrogen into the same ports used for steam injection. The SPG SGT6-5000F and MHI 501F CTGs require that nitrogen be premixed with the syngas upstream of the fuel control valve. This requirement increases the nitrogen supply pressure from 405 psia, required for the GE 7FB, to 500 psia for the SPG SGT6-5000F. This increase in supply pressure may favor adding water vapor to the syngas using low level process heat.

Existing coal-based IGCC plants do not have SCR for further control of NOx, but it is anticipated that SCR may be required on IGCC plants sometime in the future. MHI supplied the 701F CTG for the 342 MW 1x1 Negishi IGCC plant in Japan. This project began commercial operation in June 2003 and operates on residual oil. Negishi has a

NOx limit of 2.6 ppm (corrected to 15 percent O2) with an SCR removal rate exceeding 90 percent.

The SO2 emissions estimate is based on 25 ppm molar concentration of sulfur as

H2S and COS in the syngas. Reducing the syngas sulfur concentration below 25 ppm molar is well demonstrated but is more expensive than treating to the 100 to 200 ppm molar concentration practiced at the Polk and Wabash IGCC plants. More than 99 percent of the sulfur in the coal feedstock can be removed in an IGCC plant processing high sulfur coal or petcoke. For lower sulfur coals such as PRB, a sulfur removal efficiency of 98 percent is achievable. The estimated particulate emissions in Table 5-6 include fugitive emissions from coal and slag/fly ash handling. The particulate emissions in Table 5-7 were measured by sampling the HRSG stacks and do not include fugitive emissions. During normal operation, a coal fueled IGCC plant will have air emissions approaching those of a natural gas fired combined cycle plant. Flaring during startups,

shutdowns, and upsets can result in additional SO2 emissions; however, the gasification technologies under consideration (COP, GE, and Shell) can be started up and shut down

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without sour gas flaring under normal conditions. Sour gas flaring during upsets cannot be eliminated, but can be minimized by appropriate process design and operating procedures. The most common cause of flaring results from gasifiers producing more syngas than the CTGs are firing. Flaring will occur until the operating rates of the gasifiers are reduced to balance syngas production with demand. Estimated annual emissions from flaring are listed in Table 5-8. Black & Veatch developed these estimates based on 20 startups and shutdowns per year. The estimates include the GE Quench spare gasifier standby burner.

Table 5-8. Flare Emissions Estimates (tons per year)

CO2 3,000 CO 75

SO2 40 H2S 1

NOx 30 Particulate 1

Note: Based on 20 starts and shutdowns per year.

The syngas will flow through sulfur impregnated carbon, which is estimated to lower the syngas mercury (Hg) concentration below 5 ppb by weight. Assuming a mercury content in Illinois No. 6 coal of 100 to 140 ppb by weight in dry coal, the equivalent syngas mercury concentration is 50 to 70 ppb by weight, and the portion of mercury in the coal that is removed from the syngas is 90+ percent by weight (mercury concentrations range from 1 to 1,300 ppb by weight in dry bituminous coal and from 8 to 900 ppb in dry subbituminous coal). Up to 40 percent of the mercury in coal may be removed upstream of the sulfur impregnated carbon by scrubbing the syngas, which would reduce the mercury concentration to the inlet of the sulfur impregnated carbon to 30 to 42 ppb by weight. Eastman Chemical Company’s coal gasification plant has used sulfur impregnated carbon beds for mercury removal since its startup in 1993. Eastman reports 90 to 95 percent mercury removal with a bed life of 18 to 24 months and no contamination of its product.16

To reduce CO2 emissions (if required in the future), the CO in the syngas can be

reacted with water vapor to produce hydrogen and CO2. This reaction is known as shift

conversion. The CO2 can be removed by absorption in a solvent, which produces a syngas that is primarily hydrogen. The hydrogen rich syngas can be combusted,

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producing an exhaust gas that is primarily water vapor. The CO2 is recovered at low pressure and must be compressed to between 1,000 and 3,000 psig to be used for underground injection for tertiary oil recovery or geologic sequestration.

This modification, including compression, CO2 pipeline, and sequestration costs increases the cost of electricity to a total of 30 to 35 percent for new IGCC plants and 80 17 to 85 percent for new PC plants. In some locations, a major portion of the costs for CO2 removal, compression, and pipeline transportation could potentially be recovered by selling the CO2 for tertiary oil recovery. An IGCC plant can be designed for the future

addition of CO2 removal. This would involve designing the gasification process, including the ASU, to operate at a higher pressure to allow for the future addition of shift

conversion and CO2 removal. Additional plot space would also be required.

5.6.1 Water Emissions The facility will have a single wastewater stream to discharge to a receiving stream. The wastewater to discharge will be a mixture of the following streams: • Raw water clarification blowdown after solids removal. • Cooling water blowdown. • Reverse osmosis and electrodialysis reject water. • Plant drains after oil and solids removal. • Uncontaminated site runoff. Gasification process wastewater and excess coal storage runoff water will be treated by a ZLD process. Therefore, the wastewater to be discharged will only contain heavy metals that were in the incoming raw water that were not removed by the pretreatment clarification step.

5.6.2 Solids Byproducts and Wastes The facility will periodically produce various solid wastes. These wastes are briefly described in Table 5-9. The frequency of production and expected classification as hazardous are also provided. Some of the wastes streams are functions of the fuel feed rather than gasifier technology. Others are technology specific. The table is divided to indicate the wastes that are technology specific. The solid waste volumes listed in Table 5-9 are relatively small quantities compared to the byproducts listed in Table 5-6.

16Information taken from “The Cost of Mercury Removal in an IGCC Plant,” by Rutkowski, M.D.; Klett, M.G.; and Maxwell, R.C., presented at the October 2002 Gasification Technology Conference.

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Table 5-9. Solid Waste Summary

Frequency Description Produced Hazardous? Common Byproduct Rates Wastewater Sludge from ZLD Continuous Potentially Spent Carbon 12-24 months Potentially Spent Syngas Filter Candles 2-4 years Potentially Water Treatment Spent Media Weekly No COP Solvent Filter Collected Solids and Spent Weekly-monthly Potentially Filters Spent Catalyst (COS, Claus, and TGU) 2-5 years Yes, may be reclaimed Spent ASU Molecular Sieve and Activated 5-10 years No Alumina Water Treatment Settling Basin Sludge Yearly No ASU Air Filters Yearly No GE Solvent Filter Collected Solids and Spent Weekly-monthly Potentially Filters Spent Catalyst (COS, Claus, and TGU) 2-5 years Yes, may be reclaimed Spent ASU Molecular Sieve and Activated 5-10 years No Alumina Water Treatment Settling Basin Sludge Yearly No ASU Air Filters Yearly No Shell Solvent Filter Collected Solids and Spent Weekly-monthly Potentially Filters Spent Catalyst (COS, Claus, and TGU) 2-5 years Yes, may be reclaimed Spent ASU Molecular Sieve and Activated 5-10 years No Alumina Water Treatment Settling Basin Sludge Yearly No ASU Air Filters Yearly No

17 Information taken from “Cost and Performance Baseline for Fossil Energy Plants – Volume 1,” DOE/NETL-2007/1281.

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6.0 Availability and Initial Operation

In the near term, based upon historical data and current projections, an IGCC plant is not expected to be as reliable as a PC or CFB plant with respect to producing electricity from coal. Future IGCC plants without spare gasifiers are expected to achieve long-term annual equivalent availabilities18 in the 80 to 85 percent range versus more than 90 percent for future PC and CFB plants, predicated on aggressive and proactive O&M procedures. However, based on past experience, IGCC equivalent availability during initial startup and the first several years of operation is expected to be significantly lower than the long-term targets. This can be mitigated by firing the CTGs with a backup fuel, such as natural gas or low sulfur fuel oil. The equivalent availability of the combined cycle portion of an IGCC plant is expected to be above 90 percent. The equivalent availability of an IGCC plant can be increased by providing a spare gasifier. Spare gasifier economics depend on gasifier technology, cost of backup fuel, and plant dispatch economics. Long-term IGCC unit forced outage rates are expected to range from 10 to 15 percent without a spare gasifier and from 5 to 10 percent with a hot spare gasifier. The next generation of coal fueled IGCC plants should take advantage of the lessons learned from existing operating plants, but significant startup problems should be expected.

6.1 First-Generation IGCC Plants Solids-related problems (erosion, pluggage, unstable flows, and syngas cooler tube leaks) caused significant gasification downtime for all four of the coal-based IGCC plants discussed in Section 3.5. Gasifier burner and refractory maintenance also resulted in significant downtime for the COP and GE gasifiers. For the Buggenum and Puertollano plants, CTG problems related to syngas combustion and startup air extraction were also significant. Since the problems were identified, plant modifications and O&M improvements have greatly improved performance; these two plants now produce electricity at design rates and close to design efficiencies. Estimated annual equivalent availabilities for producing electricity from coal (syngas operation) are listed in Table 6-1 for all four of the coal-based IGCC plants discussed in Section 3.5. These equivalent availabilities are for electricity production from coal or petcoke; power generation from firing the CTG on backup fuel is excluded.

18 Availability data presented in this report are annual equivalent plant availabilities, which (on a 100 percent capacity utilization basis) are equal to the Equivalent Availability Factor (EAF) as defined by NERC GADS.

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Gasification process availability for each of these plants was poor during the first several years of operation and continues to be a problem. The complexity and relative technological immaturity of large-scale commercial gasification processes increase opportunities for deficiencies in design, vendor-supplied equipment, construction, operation, and maintenance. During the first several years of plant operation, most of these deficiencies were corrected, and the plant staff has optimized the plant O&M as they “move up the gasification learning curve.” Design improvements are expected to be introduced on future IGCC plants, which should improve equivalent availability.

Table 6-1. Operating Coal/Petcoke Fueled IGCC Plant Reported Availabilities19

IGCC Plant Nuon Global Energy TECO Elcogas Location Buggenum Wabash Polk County Puertollano Netherlands Indiana Florida Spain Gasifier Shell COP E-Gas GE HTHR Prenflo Net Output 252 MW 262 MW 250 MW 300 MW Startup Year 1994 1995 1996 1998 Year after Startup IGCC Equivalent Availability (percent) 1 23 20 35 16 2 29 43 67 38 3 50 60 60 59 4 60 40 75 62 5 61 70 69 66 6 60 69 74 58 7 57 75 68 NA 8 67 78 81 9 73 -- 82 10 78 -- 11 NA Notes: 1. Data is based upon available information. Data reporting methodology varies somewhat between the plants. 2. Wabash Years 5 to 8 IGCC equivalent availability estimated as 95 percent of reported syngas availability. 3. Wabash availability excludes periods when the plant was shutdown because of no product demand (24 percent in Year 7 - 2002 and 16 percent in Year 8 – 2003, shutdown in Year 9 - 2004 and Year 10 - 2005).

19 Information taken from annual plant update presentations made at the Gasification Technologies Conference from 1995 to 2005 and the Final DOE Technical Reports for the Polk County and Wabash IGCC Plants (see Footnotes 11 and 12).

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6.2 Scenarios Selected for Availability Analysis Alliant Energy and Black & Veatch agreed to consider two scenarios in greater depth. The Shell PRB scenario was selected because it has the lowest capital cost and lowest heat rate option for PRB coal. The GE Quench scenario was selected to better evaluate the impact of a spare gasifier. For each scenario, a range of expected availabilities was estimated. This range was further broken down into three cases: low, mid, and high availability. It is anticipated that Alliant Energy will evaluate the impact of these different availability cases using its economic model to better quantify the potential risk.

6.3 Next (Second) Generation IGCC Plants The projected long-term IGCC unit equivalent availability for the two scenarios considered in greater depth is as follows: • 80 to 85 percent for the Shell PRB scenario without a spare gasifier (the Shell Illinois No. 6 scenario is projected to have the same availability profile). • 85 to 90 percent for the GE Quench scenario (Illinois No. 6) with a spare gasifier. Table 6-2 lists the projected IGCC equivalent availabilities for these scenarios. Black & Veatch developed the data in Table 6-2 based on the experience of the operating coal IGCC plants indicated in Table 6-1, with adjustments for lessons learned and current technology. The estimated probabilities for achieving the low, mid, and high equivalent availabilities are 80, 50, and 20 percent, respectively. The GE Quench gasifier has the lowest cost spare gasifier and can be operated in a hot standby mode. The Shell gasifier cost is substantially higher than that of either the COP or GE unit, which makes Shell the least attractive option for sparing. It is not practical to operate with a hot spare for HTHR gasifiers, because HTHR requires a shutdown to switch the gasifiers. The COP and Shell gasifiers utilize HTHR. The spare COP gasifier at the Wabash IGCC plant has not provided sufficient benefit to justify its additional cost. GE also offers a solid fuel HTHR gasification option in which the gasifier is direct-connected to the radiant cooler, and the convective cooler is direct- connected to the radiant cooler. This configuration does not allow the addition of a spare gasifier without the addition of spare radiant and convective coolers. Long-term IGCC plant forced outage downtimes20 are expected to range from 10 to 15 percent without a spare gasifier and from 5 to 10 percent with a hot spare gasifier.

20 Forced outage downtimes presented in this report are annual equivalent plant downtime values, which (on a 100 percent capacity utilization basis) are equal to Equivalent Forced Availability Factor (EFOR) as defined by NERC GADS.

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Table 6-3 lists estimates of the forced outage downtime and the one and two train annual operation for each of the cases in Table 6-2.

Table 6-2. Estimated Availabilities for Second Generation of Coal Fueled IGCCs

Scenario Shell - PRB GE Quench - Illinois No. 6 Gasifiers 2 4 Spare Gasifier No Yes Integration Moderate Moderate IGCC Plant Equivalent IGCC Plant Equivalent Availability (percent) Availability (percent) Case Low Mid High Low Mid High Year after Startup* 1 - CT Comb Insp. 40 55 70 50 65 80 2 - CT Hot Gas Path 50 63 75 60 73 85 (HGP) Insp. 3 - CT Comb Insp. 60 70 80 70 80 88 4 - CT Comb Insp. 70 78 83 80 85 90 5 - CT/Steam 70 78 80 80 82 85 Turbine (ST) Major 6 - CT Comb Insp. 82 84 86 87 90 91 7 - CT Comb Insp. 82 84 86 87 90 91 8 - CT HGP Insp. 80 82 84 85 88 89 9 - CT Comb Insp. 82 84 86 87 90 91 10 - CT Comb Insp. 82 84 86 87 90 91 11 - CT/ST Major 76 78 80 81 84 85 Long-Term Plant 80 83 85 85 88 90 Average

*The CTG and STG inspections and major outages are shown by year.

The CTG(s) can operate on backup fuel when syngas is not available. Combined cycle availability is expected to exceed 90 percent. It appears that the prevailing sentiment in the gasification community is that a spare gasifier is probably not justified in most power generation applications. Typically, there is reduced power demand in the spring and/or fall of the year that would allow for extended planned outages to replace the refractory. The presence of a backup fuel, natural gas or oil, would allow for an overall availability above 90 percent. The cost, availability, and air emissions of backup fuel firing may limit or prevent its use. If natural gas is not available at the proposed site,

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the installation of a natural gas pipeline and supporting equipment would be required, which may contribute to higher project capital costs. These significant capital requirements may not be justified by the incremental benefit of increased plant availability with higher cost natural gas as a backup fuel, and may not justify the feasibility of an IGCC project. Likewise, using fuel oil as a backup fuel to enhance syngas production reliability would also be prohibitively expensive and logistically cumbersome.

Table 6-3. Estimated Forced Outage for Second Generation of Coal Fueled IGCCs

Scenario Shell - PRB GE Quench - Illinois No. 6 Gasifiers 2 4 Spare Gasifier No Yes Integration Moderate Moderate Case Low Mid High Low Mid High Forced Outage 14.9 11.9 9.8 9.7 6.7 4.7 Downtime, % Single Train Annual 31.3 27.1 24.1 22.0 17.8 14.9 Operation, % Two Train Annual 64.4 69.4 73.0 74.0 79.1 82.6 Operation,%

6.4 Third-Generation IGCC Plants Table 6-4 presents assumed equivalent availabilities for third-generation coal fueled IGCC plants for the two scenarios considered in greater depth in this study. Black & Veatch developed the data in Table 6-4 based on these plants taking advantage of experience gained from completed second-generation IGCC plants and technology improvements. The estimated probabilities for achieving the low, mid, and high equivalent availabilities are 80, 50, and 20 percent, respectively. Second-generation IGCC plants should be operational by 2012 to 2014. The earliest startup of coal fueled IGCC plants that could incorporate improvements from the second-generation IGCC plants is anticipated to be approximately 2016. Third generation IGCC plants starting up after 2019 should fully benefit from the second- generation IGCC plant experience.

6.5 Other Commercial Entrained flow Gasification Experience GE water quench type gasifiers have been in commercial operation on coal or petcoke since 1983, producing syngas for chemical production. Two plants of note are

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the Eastman Chemical Plant in Kingsport, Tennessee, and the Ube Ammonia Plant in

Japan. The syngas from these two plants is used to produce acetyl chemicals and NH3, respectively. Kingsport has two 1,250 tpd coal gasifiers; one is normally operated and the other is a spare. Ube has four gasifiers; three are normally operated and one is a spare. Ube originally gasified crude oil, then switched to refinery residuals, then to coal, and has been gasifying a total of 1,650 tpd of petcoke since 1996. At Kingsport and Ube, an average syngas availability of 98 percent is achieved by rapid switchover to the spare gasifier (which is on hot standby) and the high level of resources (e.g., O&M) applied to the gasification process.

Table 6-4. Estimated Availabilities for Third-Generation Coal Fueled IGCCs

Gasifier Type Shell - PRB GE Quench - Illinois No. 6 Gasifiers 2 4 Spare Gasifier No Yes Integration Moderate Moderate IGCC Plant Equivalent IGCC Plant Equivalent Availability (percent) Availability (percent) Case Low Mid High Low Mid High Year after Startup* 1 - CT Comb Insp. 55 62 70 65 72 80 2 - CT HGP Insp. 63 69 75 73 79 85 3 - CT Comb Insp. 70 75 80 80 84 88 4 - CT Comb Insp. 78 80 83 85 88 90 5 - CT/ST Major 78 79 80 82 84 85 6 - CT Comb Insp. 84 85 86 90 91 91 7 - CT Comb Insp. 84 85 86 90 91 91 8 - CT HGP Insp. 82 83 84 88 89 89 9 - CT Comb Insp. 84 85 86 90 91 91 10 - CT Comb Insp. 84 85 86 90 91 91 11 - CT/ST Major 78 79 80 84 85 85 Long-Term Average 83 84 85 88 89 90

* The CTG and STG inspections and major outages are shown by year.

The Eastman Kingsport plant has occasionally been referred to as an IGCC plant. This is incorrect because it produces no power; the Eastman plant produces syngas for chemical production, with no power generation. The economics of chemical production

June 2007 6-6 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 6.0 Availability and IGCC Technology Study – 2007 Update Initial Operation at the Eastman facility are different from the economics of the power market. As such, a fully redundant gasifier is warranted at the Eastman facility. Eastman has made gasification one of its focus areas, as evidenced by its formation of the Eastman Gasification Services Company. In January 2003, Eastman and ChevronTexaco announced a gasification services agreement, which continues to be in effect with GE. GE Quench gasifiers have a lower capital cost than gasifiers with HTHR. The GE Quench gasifier is also better suited for hot standby operation, because the spare gasifier can be quickly placed in service. Gasifiers with syngas coolers must be shut down and purged to open the blinds connecting the spare gasifier to the syngas cooler and to close the blinds connecting the shutdown gasifier to the syngas cooler. Water evaporated into the syngas in the GE Quench gasification process is well suited for the sour shift conversion of CO to hydrogen, which requires a large water vapor concentration in the syngas. Both the Eastman and Ube plants have shift conversion steps. In summary, GE Quench gasifiers are more economical than HTHR for the low capacity gasification applications associated with chemical production that include shift conversion. For larger power generation applications, higher efficiency and economies of scale make HTHR more competitive.

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7.0 Schedule and Site Layout

Based upon available information, a feasibility level schedule and a site layout were developed for a greenfield site.

7.1 Schedule A schedule has been prepared for a potential 2x1 IGCC project, which is included in this report as Appendix A. The schedule assumes that Alliant Energy would receive a “Declaratory Ruling,” allowing a limited notice to proceed (LNTP). With the Declaratory Ruling, Alliant Energy can fund the full engineering release and begin issuing bid specifications and awarding contracts prior to receipt of the air permit and the Certificate of Public Convenience and Necessity (CPCN). If Alliant Energy does not receive a Declaratory Ruling and, therefore, must wait until all permits and certificates are issued prior to releasing engineering and procurement, an estimated one full year must be added to the schedule. It has been assumed that the combined cycle construction will be completed 6 months before the first gasifier is started. The reason for this schedule is to allow time to ensure that the combined cycle equipment is working properly on natural gas before testing the integrated system. This reduces potential problems during gasifier startup.

7.2 Site Layout A generic site layout drawing for a nominal 600 MW IGCC plant at a greenfield location is included as Appendix B. The total site footprint is 250 acres. The IGCC plant equipment (including switchyard) occupies 50 acres. The balance of the acreage is for the rail loop coal and slag storage and the storm water runoff pond. The IGCC plant includes the following major facilities: • Rail loop with enclosed coal unloading and handling equipment (rapid bottom discharge bottom dump railcars). • Coal stacker/reclaimer, and transport conveyor. • Active coal storage dome (10 days’ capacity). • Inactive coal storage (30 days’ capacity). • Slag storage (1 year capacity). • Fluxant silo, conveyor, day bins, and feeders. • Gasification structure, including coal milling. • Gas treating area, including flare. • ASU.

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• Generation building. • Cooling tower. • Substation-Switchyard. • Water treatment building. • Control electrical building. • Administration building. • Warehouse/Plant services building.

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8.0 Capital and Operating Cost Estimates

This section contains Owner’s costs, EPC capital costs, and O&M cost estimates for the selected technologies. The cost estimates in this study include estimated costs for equipment and materials, construction labor, engineering services, construction management, and indirects. The estimates are based on Black & Veatch proprietary estimating templates and experience. These estimates are screening-level estimates prepared for the purpose of project screening, resource planning, comparison of alternative technologies, etc. The information is consistent with recent experience and market conditions, but as demonstrated in the last few years, the market is dynamic and unpredictable. Power plant costs are subject to continued volatility in the future, and the estimates in this study should be considered primarily for comparative purposes. The air quality control systems (AQCSs) for each technology were selected to meet typical recent

BACT levels for criteria pollutants, including NOx, SO2, PM10, and mercury. PM2.5 control was not included in the estimates. The estimate was developed using an overnight EPC cost basis. The estimates are expressed in May 2007 US dollars using the assumptions listed in Section 8.2. The total project cost (total capital requirement) equals the sum of the capital cost and the Owner’s cost. Typically, the scope of work for an EPC contractor consists of the base plant, which is defined as being within the fence boundary with distinct terminal points. Alliant Energy requested that preliminary cost estimates for the substation and utility interconnections (transmission lines, gas supply, and water supply pipelines) also be included in the preliminary EPC cost estimates in this study. Additional outside-the- fence costs (e.g., access roads and railroad) are not included in the EPC cost and are considered Owner’s costs.

8.1 Owner’s Costs The sum of the EPC capital cost and the Owner’s cost equals the total project cost or the total capital requirement for the project. Typical Owner’s costs that may apply are listed in Table 8-1. These costs are not usually included in the EPC estimate and should be considered by the project developer to determine the total capital requirement for the project. Owner’s cost items include costs for “outside-the-fence” physical assets, project development, and financing costs. Interconnection costs can be major cost contributors to a project and should be evaluated in greater detail during the site selection. The order of magnitude of these costs is project-specific and can vary significantly, depending upon technology and project-unique requirements.

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Table 8-1. Potential Owner’s Costs

Project Development: Plant Startup/Construction Support: ● Site selection study ● Owner’s site mobilization ● Land purchase/options/rezoning ● O&M staff training ● Transmission/gas pipeline rights of way ● Initial test fluids and lubricants ● Road modifications/upgrades ● Initial inventory of chemicals/reagents ● Demolition (if applicable) ● Consumables ● Environmental permitting/offsets ● Cost of fuel not recovered in power sales ● Public relations/community development ● Auxiliary power purchase ● Legal assistance ● Construction all-risk insurance ● Acceptance testing Utility Interconnections: ● Supply of trained operators to support ● Natural gas service (if applicable) equipment testing and commissioning ● Gas system upgrades (if applicable) ● Electrical transmission Taxes/Advisory Fees/Legal: ● Supply water ● Taxes ● Wastewater/sewer (if applicable) ● Market and environmental consultants ● Owner’s legal expenses: Spare Parts and Plant Equipment: ● Power Purchase Agreement (PPA) ● AQCS materials, supplies, and parts ● Interconnect agreements ● Acid gas treating materials, supplies, and parts ● Contracts--procurement and construction ● Combustion and steam turbine materials, ● Property transfer supplies, and parts ● HRSG, gasifier and/or boiler materials, supplies, Owner’s Contingency: and parts ● Owner’s uncertainty and costs pending final ● Balance-of-plant equipment/tools negotiation: ● Rolling stock ● Unidentified project scope increases ● Plant furnishings and supplies ● Unidentified project requirements ● Costs pending final agreement (e.g., Owner’s Project Management: interconnection contract costs) ● Preparation of bid documents and selection of contractors and suppliers Financing: ● Provision of project management ● Financial advisor, lender’s legal, market ● Performance of engineering due diligence analyst, and engineer ● Provision of personnel for site construction ● Development of financing sufficient to meet management project obligations or obtaining alternate sources of lending ● Interest during construction ● Loan administration and commitment fees ● Debt service reserve fund

For a screening-level analysis, the Owner’s cost, exclusive of interest during construction (IDC), can be estimated as a percentage of the EPC cost. Typically, based on actual project financial data, Owner’s costs exclusive of IDC and escalation have been found to be in the range of 15 to 20 percent of the EPC cost for PC and CFB projects.

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Additional considerations are merited for IGCC. Without a historical basis, Black & Veatch assumes 6 percent of the EPC cost. This contingency is in addition to the 15 to 20 percent Owner’s costs, exclusive of IDC, and would cover the unexpected repairs and modifications needed during the initial years of operation. To attain high availability, it is assumed that the Owner would have to aggressively correct deficiencies and implement enhancements as they were identified. Some of the costs for correcting deficiencies may be recovered from the EPC contractor, but the Owner should expect to have significant initial operating costs that will not be reimbursed by the EPC contractor. Depending on the contracting arrangement and guarantees obtained, some of this responsibility/liability might be accepted by the EPC contractor, but it can be assumed that it would result in an equivalent price increase by the EPC contractor to assume the additional risk.

8.2 EPC Capital Cost Preliminary project EPC cost estimates are presented in Table 8-2. These estimates were developed by Black & Veatch using internal cost data. The EPC Cost Estimate Scope Assumptions include the following: • Land purchase is not included. • Site is level, no rock excavation required, no trees, no dewatering, no underground obstruction, and no fill requirements. Cut and fill balance is onsite. • No hazardous and/or contaminated material will be encountered onsite, and no removal or replacement of soil is required. • Land right-of-way and permits are excluded. • No special compliance needs, such as cooling tower plume abatement, are included. • Costs to comply with any special local noise requirements are not included. • Startup and construction utilities, such as water, power, fuel, and compressed gases, are not included. • Unlimited access to the project site is available. • Suitable storage facilities/lay-down areas are available immediately adjacent to the plant site. • Construction is to be performed on a union basis. • Costs for wetlands or threatened and endangered species impact mitigation are not included. • Roadways are included only for area local to site (an access road to the site is not included).

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• No landscaping costs except overseeding have been included. • First fills of catalysts and chemicals are included. • Water termination point will be at the site boundary. • Natural gas will be used for flare pilot fuel. • No plant communications equipment is included. • Plant dispatching and any special communications are not included. The EPC Project major facilities include the following: • Temporary construction facilities. • Water management facilities including water treatment, wastewater collection and treatment, and chemical storage equipment. • ASU. • Coal milling system (with integral coal drying for Shell and slurry tanks and pumps for COP and GE). • Gasification system. • Slag handling system • Syngas treatment system (with sulfur recovery). • CTGs to burn syngas and/or natural gas. • HRSGs and associated systems to supply/receive various boiler feedwater, steam, and condensate streams to/from the gasification process. • STG. • Heat rejection equipment (cooling tower and circulating water system). • Fire protection equipment. • Coal unloading and handling equipment (rapid bottom discharge bottom dump railcars), stacker/reclaimer, and transport conveyor. • Rail loop. • Area for 40 days’ onsite coal storage (10 days active). • Flux additive handling facilities (silo, conveyor, day bins, feeders) • Onsite byproduct stockpile (uncovered) sized for 1 year of slag production. • Onsite solid waste landfill provisions. • Liquid sulfur storage pit and railcar loadout. • Control and electrical equipment for protection and operation of the plant. • Control electrical building. • Generation building. • Water treatment building. • Administration building. • Gasification laboratory.

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• Warehouse/Plant services building. Direct EPC costs include the following: • Equipment and materials. • Construction labor. • Startup spares. • Freight. • Commissioning • Performance testing, including 30 day availability test Indirect EPC costs include the following: • Engineering. • Gasification technology license (pass-through to Owner). • Construction management. • Insurance and bonds for EPC contractor. • Contingency. Owner’s costs include the following: • Project management and consulting. • Warehouse inventory, including spare parts. • Permitting and legal costs. • Taxes and fees. • Project development and contingency. Owner’s costs assume that the electricity sold during initial plant startup would cover the cost of coal and backup fuel, and no additional coal inventory would be required. Owner’s contingency includes delays and modifications not covered by the EPC Contractor Guarantees and Warrantees. Estimates are in May 2007 dollars. The estimates presented are reasonable for today’s market, but as demonstrated in the last few years, the market is dynamic and unpredictable, and costs may vary significantly depending on market conditions. Power plant costs are subject to continued volatility in the future, and the estimates in this report should be considered primarily for comparative purposes.

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Table 8-2. EPC Capital Cost Estimates

Gasifier Technology COP GE Shell Syngas Cooling HTHR HTHR Quench HTHR HTHR HTHR Coal PRB Illinois No. 6 Illinois No. 6 Illinois No. 6 PRB Illinois No. 6 Gasifier Sparing No No Yes No No No Number of Gasifiers 3 2 4 2 2 2 Gasifier Cap as % of Total IGCC 33.3% 50% 33.3% 50% 50% 50% Plant Coal Use, stpd As-Received 8,145 6,097 6,361 6,361 7,189 5,685 Oxygen Use (95% purity), stpd 5,585 5,020 5,392 5,392 3,944 4,130 Syngas to CTGs, MBtu/h (LHV) 3,762 3,762 3,762 3,762 3,759 3,762 Total EPC Cost1, $MM 1,705 1,505 1,486 1,619 1,574 1,556 Net Power, MW at 59° F with 609 602 567 599 562 569 Clean and New Equipment Total EPC Cost, $/kW 2,800 2,500 2,622 2,704 2,800 2,735 Owner’s Costs, $MM3 853 753 744 810 786 778 Total Project Cost, $MM 2,558 2,258 2,230 2,429 2,360 2,334 Specific Cost, $/kW 4,200 3,750 3,932 4,055 4,200 4,102 Notes 1. All costs are indicative estimates and exclude escalation. Accuracy is estimated at +30/-20 percent. 2. In this alternative, the Shell gasification process is sized to produce full combined cycle power output from either Illinois No. 6 or PRB coals. 3. Owner’s Costs were estimated at 50 percent of the overnight EPC cost.

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8.3 Contracting Methods Contracting options for an IGCC plant are expected to be similar to options for other solid fuel power projects. These options range from a full EPC contract to a traditional utility design project, with numerous options within that spectrum. The scope of work for gasification projects has historically been different than for traditional coal fueled plants, with turnover to the Owner shortly after mechanical completion and short- term performance testing. For IGCC projects, details regarding guarantee levels for cost, schedule, and performance; associated liquidated damages clauses and risk premiums; and availability assurances are not currently well defined. The current higher project risk of IGCC technology will require higher EPC contractor and owner contingencies than for a conventional coal fired project. As new projects progress, the EPC terms and conditions that are offered by these alliances should become available. Potential IGCC owners are stating a need for the EPC contractor to provide overall project guarantees that will “wrap” the guarantees supplied by technology and equipment suppliers. The current EPC alliances have indicated that they intend to address this issue. Regardless of how IGCC projects are financed or incentivized in the future, lending institutions have identified some keys to near-term IGCC project financing, which include accurate cash flow modeling, clear definition of project risk mitigation, and the acquisition of a bankable PPA. IGCC projects are much more complex than PC projects. For IGCC projects, EPC contractors must integrate technology and equipment from a large variety of suppliers. Gasification technology suppliers primarily license “expertise” in the form of a Process Design Package that is implemented by the EPC contractor. The only equipment provided by the gasification technology supplier consists of a few highly proprietary equipment items. In addition to gasification technology suppliers, there are other critical technology suppliers for an IGCC project, such as the following: • Combustion turbine vendors. • ASU vendors. • HRSG vendors. • Gas cleanup technology suppliers. These suppliers are critical to the success of an IGCC plant because of the highly integrated nature of the systems, and the significant capital cost and performance requirements for these system components.

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8.4 O&M Costs O&M cost estimates are presented in Table 8-4. These estimates were developed by Black & Veatch using internal data and are based on a 25 year plant life without major equipment replacement. The operating costs assume that the slag and sulfur would be sold at a price that breaks even with their handling costs. The costs include an allowance for water supply and treatment. The costs also include replacement of sulfur impregnated carbon for mercury removal, but do not include the cost of fuel (coal and natural gas). IGCC plant staffing estimates are presented in Tables 8-5, 8-6, and 8-7 for two, three, and four gasifiers, respectively. The plant staffing estimates are based on Black & Veatch experience and are based on a stand-alone plant organization with minimal administrative, commercial, and technical support from other owner locations. The nonfuel variable O&M cost breakdown for Table 8-4 is presented in Table 8- 3. Solid waste disposal (refer to Table 5-9) is included in the estimated variable costs. O&M costs will vary with how the plant is operated and maintained.

Table 8-3. Nonfuel Variable O&M Cost Breakdown

Component Percent ASU 5 Gasification and Gas Treating, except Mercury Removal 38 Mercury Removal 3 Combined Cycle 35 Balance of Plant, except water 7 Water Supply and Treatment 12

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Table 8-4. O&M Cost Estimates

Gasifier Technology COP GE Shell Syngas Cooling HTHR HTHR Quench HTHR HTHR HTHR Coal PRB Illinois No. 6 Illinois No. 6 Illinois No. 6 PRB Illinois No. 6 Gasifier Sparing No No Yes No No No Number of Gasifiers 3 2 4 2 2 2 Net Power, MW at 59° F with Clean and 609 602 567 599 562 569 New Equipment Gasifier Capacity as % of Total IGCC Plant 33.3% 50% 33.3% 50% 50% 50% Long-Term IGCC Availability, percent 82 82 90 82 82 82 IGCC Utilization Factor, percent 85 85 85 85 85 85 Long-Term IGCC Cap Factor, percent 69.7 69.7 76.5 69.7 69.7 69.7 Plant Staff 136 120 141 120 120 120 Plant Staff Expense, $MM/yr 12.6 11.1 13.1 11.1 11.1 11.1 Fixed O&M Cost, $MM/yr 16.8 15.3 17.3 15.3 15.3 15.3 Fixed O&M Cost, $/kW-yr 27.7 25.6 30.7 25.8 27.4 27.1 Variable O&M Cost, $MM/yr (Note 2) 28.5 28.0 28.0 27.5 21.9 25.5 Variable O&M Cost, $/MWh 7.71 7.67 7.43 7.58 6.43 7.41 Total O&M Cost, $MM/yr 45.4 43.4 45.3 42.9 37.3 40.9 Total Nonfuel O&M Cost, $/MWh 12.26 11.86 12.01 11.80 10.92 11.85 Notes: 1. All costs are indicative estimates in May 2007 US$ and exclude escalation. Accuracy is +30/-20 percent. 2. The IGCC Utilization Factor of 85 percent was provided by Alliant Energy. 3. Variable O&M cost is an average over a 25 year plant operating life in 2007 US$ without escalation and without major equipment replacement. 4. The GE Quench configuration includes a “hot” spare gasifier.

June 2007 8-9 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 8.0 Capital and IGCC Technology Study – 2007 Update Operating Cost Estimates

Table 8-5. Estimated IGCC Plant Staffing for Two Gasifiers

Staff per Number of Total Staff Position Shift Shifts Count Operations 56 Operations Manager 1 1 1 Shift Supervisor 1 5 5 Plant Operator 2 5 10 Asst. Plant Operator 2 5 10 Utility Operator 3 5 15 Fuel Supply Operator 2 5 10 Laborer 5 1 5 Maintenance 41 Maintenance Manager 1 1 1 Craft Supervisors 5 1 5 Maintenance Planner 3 1 3 Maintenance Clerk 3 1 3 Mechanics 15 1 15 I&C Technicians 7 1 7 Tool Room Attendant 1 1 1 Plant Helper 6 1 6 Technical Services 13 Tech Services Manager 1 1 1 Clerk 2 1 2 Engineer 3 1 3 Chemist 1 1 1 Lab Technicians 1 5 5 EH&S Administrator 1 1 1 Administration 10 Plant Manager 1 1 1 Administrative Manager 1 1 1 Materials Supervisor 1 1 1 Warehouse 2 1 2 Clerk 2 1 2 Human Resources Supervisor 1 1 1 Administrative Assistant 2 1 2 Plant Total 120

June 2007 8-10 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 8.0 Capital and IGCC Technology Study – 2007 Update Operating Cost Estimates

Table 8-6. Estimated IGCC Plant Staffing for Three Gasifiers

Staff per Number of Total Staff Position Shift Shifts Count Operations 61 Operations Manager 1 1 1 Shift Supervisor 1 5 5 Plant Operator 2 5 10 Asst. Plant Operator 3 5 15 Utility Operator 3 5 15 Fuel Supply Operator 2 5 10 Laborer 5 1 5 Maintenance 50 Maintenance Manager 1 1 1 Craft Supervisors 5 1 5 Maintenance Planner 3 1 3 Maintenance Clerk 3 1 3 Mechanics 20 1 20 I&C Technicians 9 1 9 Tool Room Attendant 1 1 1 Plant Helper 8 1 8 Technical Services 13 Tech Services Manager 1 1 1 Clerk 2 1 2 Engineer 3 1 3 Chemist 1 1 1 Lab Technicians 1 5 5 EH&S Administrator 1 1 1 Administration 12 Plant Manager 1 1 1 Administrative Manager 1 1 1 Materials Supervisor 1 1 1 Warehouse 3 1 3 Clerk 3 1 3 Human Resources Supervisor 1 1 1 Administrative Assistant 2 1 2 Plant Total 136

June 2007 8-11 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 8.0 Capital and IGCC Technology Study – 2007 Update Operating Cost Estimates

Table 8-7. Estimated IGCC Plant Staffing for Four Gasifiers

Staff per Number of Total Staff Position Shift Shifts Count Operations 62 Operations Manager 1 1 1 Shift Supervisor 1 5 5 Plant Operator 2 5 10 Asst. Plant Operator 3 5 15 Utility Operator 3 5 15 Fuel Supply Operator 2 5 10 Laborer 6 1 6 Maintenance 54 Maintenance Manager 1 1 1 Craft Supervisors 5 1 5 Maintenance Planner 3 1 3 Maintenance Clerk 3 1 3 Mechanics 22 1 22 I&C Technicians 10 1 10 Tool Room Attendant 1 1 1 Plant Helper 9 1 9 Technical Services 13 Tech Services Manager 1 1 1 Clerk 2 1 2 Engineer 3 1 3 Chemist 1 1 1 Lab Technicians 1 5 5 EH&S Administrator 1 1 1 Administration 12 Plant Manager 1 1 1 Administrative Manager 1 1 1 Materials Supervisor 1 1 1 Warehouse 3 1 3 Clerk 3 1 3 Human Resources Supervisor 1 1 1 Administrative Assistant 2 1 2 Plant Total 141

June 2007 8-12 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 9.0 IGCC Status and Advancements IGCC Technology Study – 2007 Update for Baseload Generation

9.0 IGCC Status and Advancements for Baseload Generation

This section provides an overview of the current status of some key issues involved in advancing IGCC, as well as issues that need to be addressed when considering IGCC for new utility baseload generation. Three entities - COP, GE, and Shell - have emerged as the current primary technology providers for utility-scale, solid fueled IGCC projects. When evaluating IGCC for baseload generation, its current technological and commercial maturity must be considered and compared with other coal generation alternatives, such as PC and CFB. This comparison reveals that the risk profile of an IGCC project is substantially different from that of conventional technologies for utility baseload generation. Key issues that should be considered include the following: • Comparative capital and O&M costs. • Schedule risks. • Performance risks. • Environmental emissions. • Availability. • Plant staffing. • Financing and incentives. • Public acceptance. Most of these issues were discussed in previous sections. Some of the issues can be objectively evaluated; others are more subjective and conditional.

9.1 Major Gasification Suppliers The following subsections describe the status and near-term development expectations for the three major gasification suppliers that are pertinent to IGCC considerations.

9.1.1 COP COP will be improving the E-Gas gasification technology demonstrated at the Wabash plant during its second-generation IGCC installations. One of its first efforts appears to be at the planned Mesaba IGCC plant, with the following targeted system improvements: • Implementation of a hybrid cyclone-candle filter for particulate removal. • Syngas cleanup.

June 2007 9-1 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 9.0 IGCC Status and Advancements IGCC Technology Study – 2007 Update for Baseload Generation

• Gasifier materials improvements. • Temperature monitoring. Its program initiatives will target application in oil sand recovery, improved cost and performance on subbituminous coal, carbon sequestration, and commercialization of warm gas cleanup. To achieve these initiatives, COP is attempting to develop application-specific design templates for minemouth coal gasification for syngas production, combined cycle repowering, and utility-scale IGCC power generation plants.

9.1.2 GE GE’s statements of its second-generation goals appear more geared toward market driven initiatives than technology improvements, which seem to be the emphasis of the goals of the other two technology providers. However, it is likely that GE is also working on technology enhancements GE has announced a greenfield IGCC project with PSI/Duke to study and possibly develop a new coal IGCC project in Indiana. GE also may target the conversion of natural gas to combined cycle IGCC projects. This market would allow GE to capitalize on its working knowledge of recently installed GE CTGs, adding value to clients who are now faced with natural gas fuel price risk or lenders that hold distressed assets.

9.1.3 Shell Shell coal gasification technology has recently been used in 12 new projects in China. All but one of these projects will manufacture feedstock syngas for fertilizer or methanol production; the other will produce hydrogen. Compared to the Nuon Power IGCC plant, Shell expects these projects to demonstrate the following performance and cost improvements: • Lower cost and higher capacity gasifier and syngas cooler. • Simplified steam system. • Water-cooled skirt reactor. • Slag crusher. • Unplanned outages of less than 4 percent. Shell has also developed a second-generation IGCC reference plant case study based in Holland, Michigan, to model the economics of its technology using subbituminous coals. The study found that the Shell gasification capital costs are insensitive to the difference between subbituminous and bituminous coals, petcoke/coal blends can be economical, and the Shell system does not need a spare gasifier to maintain plant reliability. Shell seems to be highlighting the subbituminous market with this case study.

June 2007 9-2 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 9.0 IGCC Status and Advancements IGCC Technology Study – 2007 Update for Baseload Generation

9.2 IGCC Development Expectations The next (second) generation of IGCC technology and the market are expected to develop in several critical areas, such as capacity, efficiency, emissions, incentives, and financing. These topics are discussed in the following subsections.

9.2.1 Plant Capacity Increases Plant capacity increases should be expected. The first generation focused on a nominal 250 MW capacity. The second generation will likely focus on the 600 to 900 MW size range, based upon 2x1 or 3x1 “F” class CTGs. A third-generation capacity target seems to be 800 to 1,000 MW, involving the “G” and “H” class technologies.

9.2.2 CTG Efficiency The National Energy Technology Laboratory (NETL) is sponsoring research and development with more efficient gas turbines. Current IGCC technology largely relies on the GE “F” class turbine and its SPG and MHI counterparts. Using GE 7FA CTGs, IGCC has achieved net plant efficiencies of 37.5 and 39.7 percent (HHV basis) at the Polk County and Wabash plants, respectively. An advanced “H” class turbine would boost net plant efficiency to 43.7 percent (HHV basis) with the GE HTHR gasifier.21

9.2.3 Plant Emissions IGCC emissions are competitive with or better than PC or CFB in all aspects.22 Low emission levels can be achieved without SCR or flue gas desulfurization (FGD). While the capital cost of IGCC is higher than that of PC or CFB, proponents point to emissions benefits as one justification for the added cost. Some opponents of PC are making efforts to classify IGCC as BACT for coal technologies. This should be an active issue in many states over the coming years. Experience at the Eastman Kingsport facility demonstrates that mercury removal costs are lower for IGCC than for conventional coal fired power generation.23 Another positive emissions attribute of IGCC is its compatibility with carbon capture

technologies. CO2 can be separated as a waste gas stream using gasification technology, as demonstrated at the Great Plains Synfuels Plant in North Dakota. Carbon capture and

21 Information taken from “From Coal or Oil to 550 MWe via 9H IGCC,” by Falsetti, JS and DePuy, RA- Texaco; Brdar, D and Anand, A - GE; and Paolino, J - Praxair; Gasification Technologies Conference, San Francisco, October 2000. 22 “An Environmental Assessment of IGCC Power Systems,” by Ratafia-Brown, JA, Nabfredi, LM, Hoffmann, JW, and Ramezan M – SAIC and Stiegel, GJ US DOE NETL, 19th Annual Pittsburgh Coal Conference, September 2002. 23 Information taken from “The Cost of Mercury Removal in an IGCC Plant,” by Rutkoswk, MD; Klett, MG; and Maxwell, RC, presented at the October 2002 Gasification Technology Conference.

June 2007 9-3 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 9.0 IGCC Status and Advancements IGCC Technology Study – 2007 Update for Baseload Generation

sequestration is seen by many as a potential tool for enhanced oil recovery by pumping

CO2 into petroleum reservoirs.

If CO2 capture is added to IGCC, there may be a technical preference to use quench gasifiers because they are better suited to the application.

9.2.4 Incentives The Energy Policy Act (EPAct) of 2005 established three investment tax credits for clean coal facilities. Qualifying IGCC projects may receive up to a 20 percent investment tax credit. The maximum value of award for all IGCC projects is $800 million, with a tentative equal split between bituminous, subbituminous, and lignite coals. No single project is eligible for more than $133.5 million in investment tax credits. The submittal date for applications was June 30, 2006. On May 24, 2006, $1 billion of the available $1.65 billion tax credits was awarded to nine planned clean coal facilities. Of the nine projects, three of the tax recipients were IGCC projects and included Duke Energy, Tampa Electric, and Mississippi Power Company, who were allocated $133.5 million, $133.5 million, and $133 million, respectively. The remaining $650 million will be available for allocation in 2007. Title IV of the EPAct of 2005 authorizes a Clean Coal Power Initiative (CCPI), providing $200 million annually for clean coal research in coal-based gasification and combustion technologies, as described below: • $140,000,000 for coal-based gasification technologies: – Gasification combined cycle. – Gasification, fuel cells, and combined cycle. – Gasification coproduction. – Hybrid gasification and combustion. – Other advanced coal-based technologies capable of producing a

concentrated stream of CO2. • $60,000,000 for other projects. To be eligible to receive the money, the project must advance efficiency, environmental performance, and cost-competitiveness well beyond the technologies that are in commercial service or have been demonstrated on a scale that the Secretary determines is sufficient to demonstrate that commercial service is viable as of the date of enactment of this Act. In addition, there were several specific projects called out, as follows: • Provides loan guarantees for a project from coal <7,000Btu/lb using IGCC, including the repowering of existing facilities that: – Combine with wind or other renewable sources.

June 2007 9-4 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 9.0 IGCC Status and Advancements IGCC Technology Study – 2007 Update for Baseload Generation

– Minimize and offer potential to sequester CO2. – Provide a ready source of hydrogen for near site fuel cell demonstrations. – May be built in stages. – Have a combined output of at least 200 MW at successively more competitive rates. – Are located in the Upper Great Plains. – Meet the technical requirements listed above. • Provides $80 million in direct loans to the owner of the Healy, Alaska clean coal technology plant. • Authorizes funds for a demonstration plant above 4,000 feet in the western part of the United States that can demonstrate the ability to use coal with an energy content of not more than 9,000 Btu/lb and is capable of sequestering

and removing CO2. Cost share subject to Section 988. • Authorizes loan guarantees for an IGCC plant of at least 400 MW that produces power at competitive rates in a deregulated market and does not receive direct or indirect subsidies from the taxpayers. • The Secretary is authorized to provide loan guarantees for at least five petcoke gasification projects.

9.2.5 Financing The following major project characteristics are typical of the criteria considered by financial institutions when evaluating projects for financing and to establish loan rates. • Projects that utilize proven technologies. • Reasonable scale-ups of existing proven equipment or a simple integration of modules that are proven at the same size, but not both on the same project. • Parent company guarantees. • Regulatory agencies’ approval. • Contractor guarantees on performance. There has been considerable discussion about the lenders’ perspective on first- and second-generation IGCC as applied toward future project financed plants. The consensus seems to be consistent with some previously discussed issues, that is, first- generation integration issues resulted in startup problems and delayed commercial operation, and turnkey EPC groups “dedicated to business” are required to remove lenders’ risks. One new financing structure that has been proposed is third party covenant financing. With this structure, banks would put up 80 percent of the capital cost in debt,

June 2007 9-5 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL 9.0 IGCC Status and Advancements IGCC Technology Study – 2007 Update for Baseload Generation

which would be backed by the federal government. This would effectively transfer the loan risk to federal taxpayers. The remaining 20 percent would be put up by the utility as equity. In regulated states, the Public Utilities Commission (PUC) would back this amount through rate guarantees that would effectively pass the risk on to the local ratepayer. These recovery mechanisms would ensure that banks earn their expected returns while the benefactors of the new technology, the taxpayer and ratepayer, bear the risk of cost overruns. As long as costs were approved by the PUC, the utility would also be insulated from cost overrun risks. Proponents feel that this financing structure would create a positive project development environment that would encourage the financing and construction of new IGCC projects. New projects would lead to increased technology maturity, and the general public would benefit from the increased efficiencies and environmental performance inherent in IGCC. Detractors think that a technology neutral benchmark, such as efficiency, may be more appropriate. An open-ended and undetermined scenario is third party covenant financing in a deregulated market, in which the ratepayer group is more fluid and less defined. This scenario is unique and would have to be determined prior to implementation in a deregulated state. Regardless of how IGCC projects are financed or incentivized in the future, lending institutions have identified some keys to near-term IGCC project financing, which include accurate cash flow modeling, clear definition of project risk mitigation, and the acquisition of a bankable PPA.

June 2007 9-6 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update Appendix A

Appendix A - IGCC Project Schedule

June 2007 A-1 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update Appendix A

COD Unit 2 Initial Firing Unit 2 COD Unit 1 Start of Construction Initial Firing Unit 1 LNTP NTP Mechanical Completion GE 7FB 2x1 IGCC Year 1 Year 2 Year 3 Year 4 Year 5 -7-6-5-4-3-2-1123456789101112131415161718192021222324252627282930313233343536373839404142434445464748495051525354

Conceptual Design Permitting/Licensing CTG BA D STG BA D HRSG BA D Recycle Gas Compressor BA D Large Heat Exchangers/ Vessels BA D Coal Handling BA D ASU BA D Transformers BA D Gasifier BA D DCIS BA D Alloy Pipe BA D

Site Preparation Sub Structures and Foundations CTG/CTG Building HRSG Erection STG Erection Coal Gasification Building Coal Gasification Coal Handling/Waste Material Handling Air Seperation Unit Water Treatment BOP Mech/Elec Construction Commissioning

B= Bid, A=Award, D = Delivery

Nominal 600 MW IGCC Plant with 2 x 1 GE 7FB Combined Cycle Schedule

June 2007 A-2 © Black & Veatch 2007 Final Report All Rights Reserved Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-03 Docket No. 6680-CE-170 Alliant Energy - on behalf of WP&L and IPL IGCC Technology Study – 2007 Update Appendix B

Appendix B - IGCC Site Layout Drawing

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-05

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Randy Bauer Author’s Title: Manager – Asset Strategy Author’s Telephone No.: (319) 786-7220 Witness: (If other than Author)

Data Request No. 2-05:

1.1 Project Description and Overview

1.1.2 Purpose and Need for Power Plant

(ref. 1-08, 1-33, 1-34, 1-163, 1-185, 1-186, 1-187, 1-188, 1-189, 1-190, and 1-192): Provide supporting documentation for the increased simultaneous import transmission capability that has been used as rationale to build NED3. Provide source material obtained from outside the company (e.g. ATC and Xcel) if internal information is not available. Such documentation should address increased transmission capability along with estimated energy prices for both on-peak and off-peak operation, with and without NED3 in operation, covering scenarios with and without the proposed new Paddock- Rockdale transmission line, and with and without the CAPX-proposed 345 kV line from Hampton Corners to La Crosse.

Response:

At this point, the supporting documentation WPL has available is the Revision 2 of the G527 Interconnection System Impact Study (ISIS) Report dated November 27, 2006 and Revision 3 of the G527 ISIS Report Addendum dated May 16, 2007, performed by ATC. WPL does not have the underlying data supporting the Report and the Addendum. ATC has indicated that such data cannot be released without a protective order being issued by the Commission.

The additional analysis requested in the Data Request has not been performed by ATC.

NED3 First Contingency Total Transfer Capability (FCTTC) analysis can be seen in the G527 ISIS Report in Tables 3.5.1 and 3.5.2. The report makes the following assumptions:

Page 1 of 2

Exhibit ___ (RDB-1) Schedule 3

• Paddock-Rockdale line in-service only in cases 6 and 7 as shown on page 20 of 44 (Note: Case #7 includes both the Paddock-Rockdale line and its associated lower voltage projects as documented in Table 3.5.4), • CAPX 2020 Phase I facilities are not included, • Hampton Corners-La Crosse line is not included, and • Dairyland Power Cooperative’s previously proposed 161 kV phase shifter project at the North La Crosse substation was included in the 2013 model.

The FCTTC analysis was performed only on system peak models, not hourly analysis to compare on-peak and off-peak results. Without the Rockdale-Paddock line, NED3 yields up to 625 MW additional import capability as shown in Table 3.5.1, Case 3 versus Case 1. With the Rockdale-Paddock line the aggregate import increase is approximately 900 MW (Table 3.5.2 Case 7 versus Table 3.5.1 Case 1).

There has been no FCTTC analysis for COL3. This is because Section 3.5 of the ISIS Report for G528 dated March 24, 2006, Columbia 550 MW unit, showed small incremental transfer capability in comparison to NED3.

PROMOD analysis for NED3 and COL3 supplied in the G527 ISIS Report Addendum makes the following assumptions, as listed on page 3 of 11 of the Addendum:

• Includes the Paddock-Rockdale line for both 2011 and 2016, • CAPX 2020 Phase I facilities are included as stated in Table 3.6.8 in 2016, and • The Hampton Corners-La Crosse line is included for 2016.

Page 2 of 2

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-06

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Jamie Niccolls Author’s Title: Sr. Delivery System Planner Author’s Telephone No.: (319) 786-4882 Witness: (If other than Author)

Data Request No. 2-06:

1.1 Project Description and Overview

1.1.2 Purpose and Need for Power Plant

(ref. 1-08, 1-33, 1-34, 1-163, 1-185, 1-186, 1-187, 1-188, 1-189, 1-190, and 1-192): Provide supporting documentation for the increased simultaneous import transmission capability that has been used as rationale to build COL3. Provide source material obtained from outside the company (e.g. ATC and Xcel) if internal information is not available. Such documentation should address increased transmission capability along with estimated energy prices for both on-peak and off-peak operation, with and without COL3 in operation, covering scenarios with and without the proposed new Paddock- Rockdale transmission line, and with and without the CAPX-proposed 345 kV line from Hampton Corners to LaCrosse.

Response:

“Increased simultaneous import transmission capability [is not being] used as rationale to build COL 3.” See Response to Data Request No. 2-05.

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-07

Data Request No. 2-07:

1.1 Project Description and Overview

1.1.2 Purpose and Need for Power Plant

(ref. 1-10) (App. A, p. 18 and Table 2.1): Complete the table in response to question 1- 10 for the year 2006 (Rows 74-80; column C).

Response:

See Attachment PSC 2-07.

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-07 Docket No. 6680-CE-170 Wisconsin Power and Light Company Page 1 of 2

2006 2005 2004 2003 2002 2001 2000 Residential Gs-1 2,978,206 3,059,284 2,842,733 2,846,941 2,885,971 2,727,994 2,529,718 Gs-3 30,010 31,552 30,752 31,853 32,078 31,801 31,540 Ms-3 854 862 838 823 797 754 808 Gw-1 16,609 18,097 18,377 19,794 20,611 20,889 21,164 Rw-1 8,664 9,870 10,954 12,134 13,100 14,345 14,518 Rw-3 2,992 3,327 3,678 3,999 4,331 4,767 5,182 Unbilled Residential Sales 9,045 (8,185) 2,236 11,879 (10,231) 28,281 65,801 3,046,380 3,114,807 2,909,568 2,927,423 2,946,657 2,828,831 2,668,731

Farm Sales Gs-1 347,733 364,260 359,552 373,104 380,056 383,138 374,780 Gs-3 26,155 27,312 22,820 25,002 23,037 22,317 21,100 Ms-3 235 240 241 239 229 214 199 Gw-1 8,195 8,695 8,841 9,263 10,459 10,760 10,952 Rw-1 1,376 1,528 1,744 1,896 2,023 2,197 2,433 Rw-3 666 716 798 838 887 949 1,079 Unbilled Farm Sales (205) (1,082) (1,115) 811 (1,925) 2,971 10,239 384,155 401,669 392,881 411,153 414,766 422,546 420,782

Small Commercial Sales Gs-1 1,136,818 1,160,704 1,119,308 1,105,620 1,107,683 1,082,227 1,009,528 Cg-2 1,074,406 1,064,060 1,035,911 1,001,061 1,003,032 969,820 933,075 Ms-3 7,468 7,362 7,186 6,921 6,767 6,488 5,996 Rw-1 290 307 352 388 430 445 489 Rw-3 69 89 151 141 145 163 163 Parallel generation 2 2

Unbilled Small Commercial Sales 8,089 (5,955) 6,437 9,240 (10,715) 22,150 43,254 2,227,142 2,226,567 2,169,345 2,123,371 2,107,342 2,081,295 1,992,505

Industrial Sales Cp-1 2,699,287 2,681,562 2,602,822 2,478,495 2,434,161 2,431,599 2,337,098 Cp-1a 482,165 456,529 431,135 392,869 387,712 352,225 393,460 Cp-1b 336,059 319,124 313,116 294,354 289,940 266,269 300,894 Cp-2 399,223 333,295 385,999 520,607 484,624 334,663 410,711 Cp-2a 421,570 452,217 477,079 453,727 466,231 658,824 696,785 Cp-2b 356,809 335,219 358,283 337,724 334,514 358,232 358,726 Cp-2c 137,718 140,070 107,541 - - Ms-3 623 623 675 711 691 661 715 Pg-S 171 7 - - - Unbilled Industrial Sales 25,083 12,802 9,093 29,012 (33,161) 45,971 82,332 4,858,708 4,731,448 4,685,743 4,507,499 4,364,712 4,448,444 4,580,721

Public Str & Hwy Lighting Ms-1 36,750 35,862 35,775 35,061 34,890 33,969 35,366 Ms-2 77 76 81 76 77 77 77 Mz-1 2,443 2,594 3,251 3,696 4,273 4,683 4,421 Unbilled Public Str & Hwy 42 (29) (1,563) 127 (400) 598 852 39,312 38,503 37,544 38,960 38,840 39,327 40,716

Interdepartment Sales 24,072 26,101 27,872 26,446 23,799 20,539 21,215

Subtotal (sales to ultimate customers) 10,579,769 10,539,095 10,222,953 10,034,852 9,896,116 9,840,982 9,724,670

Requirements Sales for Resale (w/o losses) 3,251,790 3,344,316 3,092,725 2,988,554 2,774,140 2,656,210 2,514,567 Non-Requirements Sales for Resale (w/o losses) 1,713,057 1,251,434 906,200 1,411,606 1,083,628 1,065,938 945,751 Sales for Resale 4,964,847 4,595,750 3,998,925 4,400,160 3,857,768 3,722,148 3,460,318

Totals 15,544,616 15,134,845 14,221,878 14,435,012 13,753,884 13,563,130 13,184,988

Company Use 7,978 9,591 14,036 14,835 29,642 17,926 18,759

Energy Losses 52,736 284,275 662,369 708,971 871,937 578,975 693,164 Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-07 Docket No. 6680-CE-170 Wisconsin Power and Light Company Page 2 of 2

2006 2005 2004 2003 2002 2001 2000

Total 15,605,330 15,428,711 14,898,283 15,158,818 14,655,463 14,160,031 13,896,911

Historical Load Appx A p 19 14,545,000 14,637,000 13,944,000 13,696,000 13,481,000 13,064,000 12,982,000

Difference 1,060,330 791,711 954,283 1,462,818 1,174,463 1,096,031 914,911

Non-requirements sales & losses 1,729,093 1,280,823 954,083 1,477,625 1,148,100 1,119,815 968,517 MISO adjustment (665,828) (464,580) Adjustment 1,063,265 816,243 954,083 1,477,625 1,148,100 1,119,815 968,517

Remaining difference (2,935) (24,532) 200 (14,807) 26,363 (23,784) (53,606)

Remaining Difference as a percent of total -0.02% -0.16% 0.00% -0.10% 0.18% -0.17% -0.39% Find 5 year average losses (2000-2004) based on FERC Form 1 Total Energy (FERC Form 1) 14,898,283 15,158,818 14,655,463 14,160,031 13,896,911 -Non-Req Sales for Resale w/losses (FERC Form 1) (954,083) (1,477,625) (1,148,100) (1,119,815) (968,517) Native Load per FERC Form 1 w/losses w/WPPI PR-1 13,944,200 13,681,193 13,507,363 13,040,216 12,928,394 -WPPI PR-1 (551,990) (450,133) (317,093) (401,502) (370,117) FERC Form 1 Native Load w/losses w/o WPPI PR-1 13,392,210 13,231,060 13,190,270 12,638,714 12,558,277 -sales to ultimate customers (10,222,953) (10,034,852) (9,896,116) (9,840,982) (9,724,670) -Req Sales for Resale w/o losses (includes WPPI PR-1) (3,092,725) (2,988,554) (2,774,140) (2,656,210) (2,514,567) +WPPI PR-1 551,990 450,133 317,093 401,502 370,117 Native load losses exclusive of WPPI PR-1 load 628,522 657,787 837,107 543,024 689,157 % Native losses 4.7% 5.0% 6.3% 4.3% 5.5% 5 year average losses 5.2% Add average losses to 2005 and 2006 FERC Form 1 data Sales to ultimate customers 10,579,769 10,539,095 Req Sales for Resale (includes WPPI PR-1 removed from load in loss calculations since they cover WPPI PR-1) 3,251,790 3,344,316 transmission losses. -WPPI PR-1 (621,935) (602,092) Subtotal energy w/o losses and note that these losses are much higher than FERC Form 1, but more w/o WPPI PR-1 13,209,624 13,281,319 closely match historic data. average losses of 5.2% 718,564 722,464 Total FERC Form 1 Native Energy without WPPI PR-1, adjusted for typical losses 13,928,188 14,003,783 Remove WPPI PR-1 from Historical Load Native Load with losses (Historical Load) 14,545,000 14,637,000 less WPPI PR-1 (621,935) (602,092) Historical Native energy w/losses and w/o WPPI PR-1 13,923,065 14,034,908 Compare 2005 and 2006 adjusted native energy to Historical Load Appx A p 19 Total FERC Form 1 Native Energy without WPPI PR-1, adjusted for typical losses 13,928,188 14,003,783 note that when typical losses are used, the adjusted FERC Form 1 Historical Native energy w/losses data matches Historical Load. and w/o WPPI PR-1 13,923,065 14,034,908 difference (5,123) 31,125 % difference 0.0% 0.2% Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-08

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Randy Bauer Author’s Title: Manager Asset Strategy Author’s Telephone No.: (319) 786-7220 Witness: (If other than Author)

Data Request No. 2-08:

1.1 Project Description and Overview

1.1.2 Purpose and Need for Power Plant

(ref. 1-11) (App. A, p. 18 and Table 2.1): Explain the increase shown in Table 1-10 for the MISO adjustment in 2005 and 2006 (Row 79).

Response:

Historically, 2000-2004 system losses in FERC Form 1 averaged about 5.2% or 670,000 MWH. 2005 FERC Form 1 system losses were about 284,000 MWH and 2006 FERC Form 1 system losses were about 53,000 MWH. This is shown in the response to Data Request No. 2-07.

WPL believes that this significant loss change is a result of data reporting issues relating to the effects of MISO Day 2 dating back to April 2005. The onset of MISO Day 2 has not significantly physically changed the transmission and distribution systems but WPL has only reported distribution losses since April 2005.

WPL staff has discussed with PSC staff concerns that MISO reports transactions at distribution substations, which neglects the effects of estimated 3.25% transmission system losses. WPL’s 2006 FERC Form 1 notes “Total Energy Losses do not include Transmission Losses which are settled financially through the MISO market.” Also, MISO may release delayed energy adjustments in the future.

Historical demand and energy is based on actual GMS data, with control area adjustments. This metering and the calculation to find native load has not changed since the onset of MISO. GMS still calculates the values based on generation output plus transmission tie adjustments. Page 1 of 2

Exhibit ___ (RDB-1) Schedule 3

In the file attached to Data Request No. 2-07, it is shown that the 2005 and 2006 historical load, based on GMS data, matches a “bottom up” comparison of FERC Form 1 load plus typical 5.2% system losses. After allowing for typical system losses it can be seen that there is only a 0.2% difference between the historical/GMS data versus FERC Form 1 load plus typical losses.

Page 2 of 2

Exhibit ___ (RDB-1) Schedule 3

CONFIDENTIAL Attachments

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-09

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Randy Bauer Author’s Title: Manager Asset Strategy Author’s Telephone No.: (319) 786-7220 Witness: (If other than Author)

Data Request No. 2-09:

1.1 Project Description and Overview

1.1.3 Alternatives

(ref. 1-17 (1.1.3, p. 33)): As requested in 1-17, provide EGEAS analysis of both 400 MW and 500 MW shares of a Supercritical PC unit at Columbia.

Response:

See EGEAS files provided via compact disk. For comparative purposes, the EGEAS runs change only the capacity ratings of the COL4 unit. Other parameters, such as fixed and variable O&M, emission rates, fuel costs, heat rates, etc were not modified.

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-10

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Steve Jackson Author’s Title: Sr. Environmental Specialist Author’s Telephone No.: (608) 458-5704 Witness: (If other than Author)

Data Request No. 2-10:

1.1 Project Description and Overview

1.1.3 Alternatives

(ref. 1-18): Provide an updated table with supercritical pulverized coal emissions.

Response:

In WPL’s original response to Data Request No. 1-18, a table was provided that represented CO2 emissions from 300MW, 400MW, and 500MW CFB and subcritical PC (SPC) units. WPL did not evaluate emissions from a supercritical PC (SCPC) unit since the proposed project does not include a SCPC unit, primarily because a 300MW SCPC unit is not a cost-effective option to the 300MW CFB and SPC.

Nevertheless, WPL has since investigated differences in CO2 emissions for a SCPC compared to a CFB and SPC. WPL’s CPCN application included efficiency information for the 300MW CFB at 35.5%. Similarly, the CPCN application identified the efficiency for a 300MW SPC at 34.7%. The USEPA has established an efficiency for a SCPC unit utilizing subbituminous coal at 37.9% and 38.3% for a SCPC unit utilizing bituminous coal. This results in the CO2 emissions comparison presented in the following tables. Table 2-10-A assumes that a SCPC unit will consume 3.2% less fuel than WPL’s proposed 300MW SPC unit (which plans to utilize only subbituminous coal) and therefore will have 3.2% less CO2 emissions. Table 2-10-B assumes that a SCPC unit will consume 2.4% less fuel than WPL’s proposed 300MW CFB (which plans to utilize subbituminous and bituminous coals, pet coke, and biomass) while generating the same level of output.

Page 1 of 2

Exhibit ___ (RDB-1) Schedule 3

Table 2-10-A: Comparison of Subcritical to Supercritical CO2 Emissions

Unit Type 300 MW 400 MW 500 MW Subcritical 2,683,177 3,568,204 4,467,280 Supercritical 2,597,316 3,454,022 4,324,327 * Based on subbituminous coal * Emissions based on 87% equivalent availability factor * Emission factors used for Subcritical unit based on AP-42, section 1.1. * Supercritical unit emissions assumed to be 3.2% less than Subcritical unit due to efficiency

Table 2-10-B: Comparison of Circulating Fluidized Bed to Supercritical CO2 Emissions

Unit Type 300 MW 400 MW 500 MW Circulating Fluidized Bed 2,594,449 3,449,186 4,319,042 Supercritical 2,532,183 3,366,405 4,215,385 * Based on CFB using subbituminous coal/pet coke blendl * Emissions based on 87% equivalent availability factor * Emission factors used for Subcritical unit based on AP-42, section 1.1. * Supercritical unit emissions assumed to be 2.4% less than CFB unit due to efficiency

Page 2 of 2

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-11

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: John Oswald Author’s Title: Environmental Lead – Wisconsin Baseload Author’s Telephone No.: (608) 458-4882 Witness: (If other than Author)

Data Request No. 2-11:

1.1 Project Description and Overview

1.1.3 Alternatives

(ref. 1-21): Will the air permit for NED3 require additional pollutant controls for NED1 and NED2? If yes, please explain.

Response:

The air permit for NED3 will not require additional pollutant controls for NED1 and NED2.

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-12

Data Request No. 2-12:

1.1 Project Description and Overview

1.1.3 Alternatives

(ref. 1-21): Will the air permit for COL3 require additional pollutant controls for COL1 and COL2? If yes, please explain.

Response:

The air permit for COL3 will not require additional pollutant controls for COL1 and COL2.

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-13

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Mel Miranda Author’s Title: Finance Manager – Wisconsin Baseload Project Author’s Telephone No.: (608) 458-3246 Witness: (If other than Author)

Data Request No. 2-13:

1.1 Project Description and Overview

1.1.4 Costs

(ref. 1-30): Provide the cost estimate requested in 1-30 in an Excel electronic format with a breakdown by major component/contract (not by FERC account). An example of this type of breakdown is WPSC’s cost estimate for Weston 4 at http://lx01/apps/erf_share/view/viewdoc.aspx?docid=12167. The estimate should address, among others, the following:

a) Explain how $777 million in capital costs (p. 22 of the application) equates to $855 million under FERC accounts (response to 1-30). b) The cost of duct improvements as per 1-31. c) The costs of rail cars as per 1-41 (if included). d) The cost of extraction steam upgrades as per 1-55. e) The cost of rail improvements as per 1-56. f) The cost of barge improvements as per 1-56. g) The cost of lime handling improvements as per 1-59. h) Other completeness items which may impact the cost substantially, like owners’ cost, construction management, cost escalation, AFUDC, and/or CWIP. i) The cost breakdowns for items (or percent of items) WP&L assumes will be shared between the new unit and the existing units.

Response:

a) The $777 million value is the estimated capital cost for the project expressed in 2007 dollars. The $855 million value represents the same capital cost but expressed in year of occurrence dollars, i.e., includes escalation. A spreadsheet, containing a cost breakdown by major component/ contract and a reconciliation Page 1 of 3

Exhibit ___ (RDB-1) Schedule 3

of the $777 million capital cost in the original CPCN Application to the $855 million cost reported in the Response to Data Request 1-30 and other documents, is attached.

The cost estimates set forth in this Response and in the attached spreadsheet are based on bottom-up estimates WPL had received prior to the time the CPCN Application was filed. In preparing the attached cost estimate, WPL has relied on the market information assembled by the original provider of the cost estimate and on the market knowledge of WPL’s owner’s engineer. Market conditions and the scope of the project have been changing since WPL received the original estimates, and the information set forth herein and in the attached cost estimate is an attempt to break down the original estimate as requested. WPL will continue to assemble market information and provide updated estimates in testimony. WPL is continuing to work toward detailed engineering design and specifications, which should further refine the actual costs for the project as the CPCN process continues.

b) The question appears to refer to 1-32, instead of 1-31. If this is correct, no capital costs for duct “improvements” were included in the NED 3 cost estimate; such improvements are addressed in the NED Units 1&2 AQCE Project (see separate Certificate of Authorization application). The NED 3 cost estimate includes only the costs for ductwork associated with the NED 3 construction, which are included in the Boiler Island and Scrubber line items of the attached estimate and amount to $1.2 million.

c) Capital costs for procurement of rail cars were not included in the NED 3 capital cost estimate, as such cars are expected to be leased (lease costs are an operating and maintenance cost). So, the capital cost of the rail cars is zero, and their lease cost is $2.3 million, per the Response to Data Request 1-41.

d) No potential steam customers have been identified for the project. As a result, the project capital cost estimate does not include any extraction steam upgrades as there is no basis for sizing it, nor is a design available.

e) The capital costs of anticipated project rail improvements are included in the Yard Structures and Industrial Tracks and Fill line items in the attached cost estimate. The costs for the railroad relocation project north of NED, at the time of the CPCN Application, was $15,600,000.1 The cost for rail improvements on-site is $4,500,000.

f) The capital costs of anticipated project barge unloading improvements are included in the attached cost estimate. The cost within the Site Preparation, Foundations and Coal Handling Equipment line items related to barge improvements is $6.7 million.

1 The new costs, as described in Response to Data Request 2-31 as Alternative 2B and in the Practicable Alternatives Analysis table, is $23 million. Page 2 of 3

Exhibit ___ (RDB-1) Schedule 3 g) The capital costs of anticipated project lime handling improvements (associated with scrubber) are included in the attached cost estimate. The cost within the Site Preparation, Balance of Plant Piping, Electrical Construction, and Scrubber line items related to lime handling equipment is $2.1 million. h) The attached cost estimate contains “other completeness costs” associated with the project such as Owner’s Costs, EPC Construction Management, Project Escalation, etc. AFUDC/CWIP costs are not included in the project capital cost estimate. i) The estimated cost of shared items that will benefit NED 3 as well as the existing NED Units 1&2 is $149 million in 2007 dollars, or $167 million in year of occurrence dollars, i.e., with escalation included. The cost breakdown for the items is as follows:

ITEM TOTAL (million $) Coal Handling, Foundation, Electrical, $60 Construction Limestone Handling $19 Ash Handling $22 RR Siding & Barge $31 Stack and Fndn. $11 Interconnection Transmission $24 Total $167

The intended use of a shared cost summary was simply to assess the benefits of construction planned for NED 3 as they impact existing NED Units 1&2, as a means of estimating project costs on an effective cost per kW basis and does not affect the project costs.

Page 3 of 3

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-13 Wisconsin Power and Light Company Docket No. 6680-CE-170

Line # Description Estimated Costs 1 DIRECT PURCHASE EQUIPMENT 2 Civil/Structural Equipment 3 Cranes and Hoists 987,100 4 Platforms related procurement 25,300 5 Civil/Structural Equipment Sub-Total $1,012,400 6 7 Mechanical Equipment 8 Steam Turbine Generator 34,400,100 9 Condenser and Air Removal Equipment 3,480,300 10 Boiler Feedwater Pumps 2,264,700 11 Condensate Pumps 503,700 12 Circulating Water Pumps 1,362,600 13 Miscellaneous Pumps 900,000 14 Compressed Air Equipment 184,300 15 Deaerator 586,400 16 Closed Feedwater Heaters 1,600,900 17 Miscellaneous Heat Exchangers 237,400 18 Ash Handling Equipment (Bottom and Fly Ash) 14,445,000 19 Limestone Handling Equipment 9,597,900 20 Demineralizer 1,184,800 21 Condensate Polisher 5,197,700 22 Chemical Feed Equipment (Boiler Treatment) 142,300 23 Chemical Feed Equipment (Cooling Tower) 173,200 24 Raw Water Treatment Equipment 2,697,200 25 Water Sampling and Analysis Panel 295,000 26 Wastewater Treatment Equipment 875,700 27 Other Mechanical Equipment and Systems 785,400 28 Mechanical Sub-total $80,914,600 29 30 Miscellaneous Mechanical Equipment 31 High Energy Piping 13,757,300 32 Circulating Water Piping 1,177,700 33 Balance of Plant Piping 20,704,100 34 Piping Specials 1,100,000 35 Control Valves 1,139,500 36 Shop Fabricated Tanks 244,900 37 Oil/Water Separator 224,000 38 Other Mechanical Equipment 4,055,500 39 Miscellaneous Mechanical Equipment Sub-Total $42,403,000 40 41 Electrical Equipment 42 Generator Step-Up Transformer 3,296,000 43 Unit Auxiliary and Reserve Auxiliary Transformers 3,605,000 44 Isolated Phase Buss Equipment 1,378,700 45 Emergency Diesel Generator 655,500 46 Medium Voltage Switchgear 7,042,700 47 480V Switchgear and Transformers 1,231,500 48 480V Motor Control Centers 996,500 49 Electrical Control Boards/Panels 209,500 50 Battery and UPS System 686,000 51 Relay and Metering Panels 319,500 52 Other Electrical Equipment 184,400 53 Electrical Equipment Sub-Total $19,605,300 54

1b of 3 Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-13 Wisconsin Power and Light Company Docket No. 6680-CE-170

Line # Description Estimated Costs 55 Control Equipment 56 Distributed Control System 2,355,000 57 CEMS System 398,000 58 Instrumentation 1,939,100 59 Instrument Tubing, Enclosures 130,800 60 Control Equipment Sub-Total $4,822,900 61 62 DIRECT PURCHASE EQUIPMENT SUB-TOTAL $148,758,200 63 64 ERECTED EQUIPMENT AND CONSTRUCTION 65 Civil/Structure Construction 66 Site Preparation 19,367,200 67 Yard Structures 4,498,000 68 Power Plant Structures 35,402,500 69 Foundations 21,143,600 70 Final Painting 806,300 71 Industrial Tracks and Fill 15,614,900 72 Other Construction 3,742,500 73 Civil/Structure Construction Sub-Total $100,575,000 74 75 Furnish and Construct Packages 76 Boiler Island 132,254,100 77 Scrubber 34,697,000 78 Cooling Tower 9,450,000 79 Coal Handling Equipment 34,042,100 80 Fire Protection Systems 1,650,000 81 Chimney - 1 Flue Only 3,609,900 82 Pre-Engineered Buildings 1,738,400 83 Insulation and Lagging 8,332,500 84 Field Erected Tanks 1,182,500 85 Other Packages 6,233,900 86 Furnish and Construct Packages Sub-Total $233,190,400 87 88 Mechanical Construction 89 HVAC and Dust Collection Erection 2,302,100 90 Mechanical Construction Sub-Total $2,302,100 91 92 Electrical Construction 93 Electrical Construction - Bulks, Misc 19,904,800 94 Other Construction 2,705,000 95 Electrical Construction Sub-Total $22,609,800 96 97 ERECTED EQUIP. AND CONSTUCTION SUB-TOTAL 98 Prime/Sub Construction Supervision 24,682,000 99 Contractor OH & Fees 51,296,000 100 101 EQUIPMENT AND CONSTRUCTION TOTAL $583,413,500 102

2b of 3 Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-13 Wisconsin Power and Light Company Docket No. 6680-CE-170

Line # Description Estimated Costs 103 PROJECT INDIRECTS 104 Engineering 33,400,000 105 EPC Construction Management 30,624,300 106 Preoperational Testing, Start-Up and Calibration Services 13,832,700 107 Construction Equipm. & Indirects 37,853,500 108 General Liability and Umbrella 4,847,000 109 Performance Bonds 9,893,800 110 111 PROJECT INDIRECTS SUB-TOTAL $130,451,300 112 113 OWNER'S COSTS 114 Project Development & Owner's Engineer 5,000,000 115 Owner Operations Personnel 3,510,000 116 Legal Council 3,000,000 117 Proj. Mngt, Construction Mngt, Start-Up 3,066,000 118 Land 681,000 119 Economic Development 1,363,000 120 Start-Up and Initial Testing 273,000 121 Fuel - Coal 5,832,000 122 Fuel - Fuel Oil 807,000 123 Reagent - Lime and Limestone 32,000 124 Variable O&M - Water, Chemicals, etc. 2,137,000 125 Test Power Sales (credit) -1,600,000 126 Site Security 1,888,000 127 Transmission Interconnection and Upgrades 24,000,000 128 Operating Spare Parts 3,500,000 129 Workshop Tools and Test Equipment 340,000 130 Warehouse Shelves 409,000 131 Mobile Equipment and Vehicles 2,249,000 132 Laboratory Equipment and Furniture 477,000 133 Building Furniture 178,200 134 Builder's Risk Insurance 4,116,000 135 Sales Tax 1,455,000 136 137 OWNER'S COST SUB-TOTAL $62,713,200 138 139 PROJECT GRAND TOTAL in 2007 dollars $776,578,000 140 141 Escalation 78,263,000 142 143 PROJECT ESCALATION SUB-TOTAL $78,263,000 144

145 PROJECT GRAND TOTAL in year of occurance dollars $854,841,000

3b of 3 Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-15

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Kirby Letheby Author’s Title: Team Lead - New Generation Author’s Telephone No.: (608) 458-3276 Witness: (If other than Author)

Data Request No. 2-15:

1.1 Project Description and Overview

1.1.14 Fuel

(ref. 1-62 (1.1.14.1, pp. 80 ff)):

a) Identify potential biomass (e.g. woodlands, poplar, switchgrass) supply aggregators and processors. How would they operate? How will supply contracts be structured to maintain forest sustainability or farmland sustainability?

b) Provide details about the biomass fuel boiler delivery and feed systems.

Response:

1) Individuals or companies viewed as examples of the potential supply aggregators of the biomass, and descriptions of who they are.

Fuel Supply Markets

Supply markets for energy fuels such as coal, oil and natural gas currently exist to meet demand for these products. Energy suppliers process these energy materials into fuel grade quality and provide robust and competitive market driven supplies. Because current demand for biomass fuels is not as robust, the biomass fuel supply market has not yet evolved to this stage of development. The NED 3 plant provides a biomass fuel end use potential to support the establishment of biomass fuel supply.

Page 1 of 7

Exhibit ___ (RDB-1) Schedule 3

WPL has gained considerable knowledge on biomass markets and aggregators from its sister utility’s experience co-burning switchgrass at its Ottumwa Generating Station located near Chillicothe, IA. Interstate Power and Light Company (IPL) has worked with the Chariton Valley Resource Conservation and Development Inc., Prairie Lands Biomass LLC, and the U.S. Department of Energy on several test burns of switchgrass. The Project’s partners have worked to demonstrate the technical and commercial feasibility of producing power from locally-grown and harvested renewable fuel resources: switchgrass and other native southern Iowa grasses. The project is managed by the Chariton Valley Resource Conservation and Development, Inc., based in Centerville, IA, and involves the efforts of project partners and team members from Iowa to Denmark. The project has worked to develop a new business opportunity for Southern Iowa farmers, while creating local environmental benefits by improving air emissions, improving soil conditions on local farm lands, enhancing wildlife habitats, and reducing sediment and nutrient run-off from farm lands into local surface waters.

The primary goal of the federally cost-shared phase of the Chariton Valley Biomass Project is to conduct all necessary research, demonstration, analysis, planning, development, and outreach work required to lay the groundwork for commercializing the Project. By creating a commercially operating switchgrass fuel supply business in southern Iowa, the Project seeks to bring a new source of revenue to Iowa farmers while creating significant environmental benefits for local air, water, soil, and wildlife.

At its core, the Chariton Valley Biomass Project is aimed at generating economic and environmental benefits for the region’s farms. The Project team, led by efforts from researchers from Iowa State University and the University of Iowa, has completed studies in the following areas: fertility and yield trials, soil stabilization and soil quality, water quality impacts, carbon sequestration, avian and wildlife impacts, intercropping systems, yield optimization, cool season grass trials, disease and weed control, switchgrass production economics, switchgrass gasification research and analysis, determining chemical characteristics for switchgrass and cool season grasses in the Project region, life-cycle greenhouse gas emissions, and valuation of societal benefits from the Project. These studies have helped to quantify the potential benefits and impacts of the Project and have helped to establish valuable management guidelines for Project partners.

WPL is utilizing the knowledge gained from this Project to help identify potential aggregators and develop a sustainable biomass market for the NED 3 facility.

Biomass Fuel Supply Markets

Currently, as there are no industries using large amounts of biomass fuel in Southwestern Wisconsin, there are few supply chains or aggregators present in the region. However, a number of organizations and companies can be viewed as examples of potential aggregators and suppliers of the biomass fuel for NED 3. WPL continues working with a number of these organizations that have

Page 2 of 7

Exhibit ___ (RDB-1) Schedule 3

expressed interest in addressing issues involved with biomass material aggregation, and biomass fuel processing, supply and transportation.

Working with the newly formed Office of Energy Independence, Wisconsin Department of Agriculture Trade and Consumer Protection, the University of Wisconsin’s Renk Agribusiness Institute and the UW Extension System, WPL is in the process of building the biomass fuel business model for NED 3. Thus far, there has been interest from private entities in aggregation along with the processing and supply of biomass fuel. The Wisconsin Co-op Association is willing to actively facilitate organizing private sector participation in supplying, processing and transporting appropriate biomass fuels. The Prairie Lands Bio- Products, Inc, was the farm organizational structure that worked with the Chariton Valley switch grass project at IPL’s Ottumwa, Iowa generation station.

2) Types of biomass expected to be supplied by the different potential suppliers (e.g. farm-grown switchgrass, farm grown poplars, woody industrial waste from particular industrial plants).

Biomass Fuel Types

There are four primary types of biomass fuel that WPL currently expects could be supplied by the different potential suppliers. The use of the Circulating Fluidized Bed (CFB) boiler design lends itself to this wide range of fuel choices including the potential for these types of biomass fuels. The primary fuel for this unit will be coal. The biomass fuel choices identified and being actively pursued so far are: wood chips/forest residues, agricultural crop residues, ethanol by-product residues and farm grown switchgrass/energy crops. The potential for use at NED 3 of each of the identified biomass fuels varies based on energy content, availability, cost, proximity, handling limitations, chemical content, and quantity. The biomass fuel will be supplied to the plant by independent supply aggregators and processors.

3) Amounts of the different types of biomass that would be expected to be used (this should include how many tons/pounds of different biomass types and also how many acres would be required, if any, for their production).

Biomass Fuel Quantities

The expected range of biomass fuel utilization for NED 3 is about 100,000 to 150,000 tons per year. This expected range is based on the assumed heat content of the biomass fuel. At production rates of 3 tons per acre per year this supply would require approximately 30,000 to 50,000 acres dedicated to annual production of this fuel. With production rates of 5 tons per acre per year this

Page 3 of 7

Exhibit ___ (RDB-1) Schedule 3 supply would require approximately 20,000 to 30,000 acres dedicated to annual production of this fuel.

While there may be a mix of biomass fuels, a primary biomass fuel was selected to allow a boiler and material handling system to be designed. For this design basis, wood chips has been selected based on suitable industry experience.

Agricultural crop residue and farm grown switchgrass yields fall into the 3 to 5 tons per acre per year production estimate. It is anticipated that sustaining this supply of biomass fuel may require using more than one agricultural biomass material (e.g., stover and hay). This will be a materials handing system challenge. Given its design basis for wood chips, the NED 3 biomass fuel material handling system design will thus require agricultural residue and switchgrass biomass fuels that are “densified” prior to arriving on site. This densification process will also simplify and increase the use of a combination of these biomass material types (that are processed into densified biomass fuels) to meet the required supply tonnage and acreage, as long as such is supplied within heat content and chemical characteristics required for long-term boiler operations.

4) Biomass sources being considered (e.g. local farms within 50-75 miles of the plant, farms in other areas that would be aggregated locally, sources of expected woody industrial waste) and, if possible, their priority order. Also if possible, provide localities of the expected potential sources.

Biomass Fuel Sources & Priority Order

Biomass sources being considered are: 1) wood chip/forest residue from local logging companies and forest management companies, whether local or, where a suitable transportation infrastructure exists, from outside the local area; 2) agricultural crop residue from local ag producers where removal of excess residue will not inhibit soil yield and farming practices; 3) ethanol plant by-product where excess dried distillers grain or thinstillage syrup is identified and processed onto a useable fuel; and 4) farm grown switchgrass where acreages have appropriate yields.

Woody biomass is the biomass fuel source with the most commercial combustion experience. Agricultural crop residues are produced by existing infrastructure and represent some of the largest local quantities of potential materials available in a reasonable radius from the plant site. Ethanol plant by-products are also produced by existing infrastructure and represent a potential win-win solution on supply and material handling, if this material can be effectively pre-processed into an acceptable fuel. Switchgrass is being produced as a result of land management synergies and presents the potential for expanded production. Each of these potential biomass materials present fuel combustion chemistry and material handling challenges that must be managed.

Page 4 of 7

Exhibit ___ (RDB-1) Schedule 3

A specific source location or amount of each biomass type has not been finalized. Combustion experience supports wood material use while local agricultural residues provide significant quantities on materials. Fuel quality specifications will create fuel processing challenges for these biomass materials. The future supply portfolio of these potential biomass fuels will be based on the ability to meet these challenges. Additional study is underway by the Southwest Badger RC&D to assist in making determinations regarding the location and estimated yields of material best suited for use as a biomass fuel for NED 3. The forest yield portion of the study should be completed before year end.

5) To whom, at a minimum, will WPL distribute the biomass fuel specification and request for proposal?

Biomass Fuel Supply Contracts

As plant design and biomass fuel research progresses, WPL will be defining and communicating biomass fuel specifications and requests for biomass fuel proposals. Such requests will be made to qualified biomass fuel processors and/or suppliers. For the biomass fuel industry to develop this business segment must be established, and it is clear that an understanding of an economics model that sustains long-term participation and partnerships is needed. Biomass fuel supply contracts will need to be structured to support this long term participation. It is not known, at this time, if WPL will be part of the process of submitting request for proposals (RFP) and vendor selection regarding suppliers of biomass fuel for NED 3. The ownership of the biomass fuel aggregation process may well be held by a private entity. WPL would then solicit the aggregator for supply of biomass fuels by type, amount and specification. The aggregator would be responsible for the RFP process to biomass material suppliers.

Potential biomass fuel suppliers and aggregators are independent organizations that procure, recover, process, store, and deliver biomass materials to their clientele (e.g., WPL) for a fee. These firms work with sources (farmers, forestry companies, other industries) to obtain raw materials generally meeting the requirements of client fuel supply and then process such materials to meet required as-delivered properties (e.g. heat content, sizing, moisture content, production standards/specifications, and chemistry). Some aggregators are simply transportation firms who work with third-party processors to complete the processing step prior to delivery, while others are the actual source of the material, processor, and transporter. Given that transportation costs need to be minimized, it is likely that most biomass material sources will be close to NED 3 (e.g., within 50-100 miles)

All aggregator supply contracts will be structured to ensure that minimum sustainability standards are maintained in growth areas. In the case of agricultural products and energy crops (e.g., switchgrass fields, poplar/willow), biomass providers will grow and harvest products using accepted soil and water management practices. It is anticipated that a minimum stock of the material will

Page 5 of 7

Exhibit ___ (RDB-1) Schedule 3

be retained by the farmer(s) for soil nutrient maintenance and other environmentally beneficial aspects. Similarly, for forestry products, it is expected that WPL will only work with suppliers and aggregators of woody biomass products that are actively engaged in approved forest management practices, and will seek to support the Statewide Forest Plan aimed at promoting sustainable forest growth. Other sources of woody biomass, such as bark and residue, will typically be waste products from another industry or process and sustainability requirements will not apply.

Biomass Fuel Specifications

It is expected that WPL will issue biomass fuel specifications and requests for proposals to multiple biomass fuel aggregators and suppliers, and then will negotiate supply contract(s) on the basis of responses. Upon receipt of contract, the aggregator(s) will be responsible for producing the biomass fuel as dictated by growing season and availability including creation of sufficient material stocks to sustain supply during non-growing seasons. NED 3 will not have space for long- term storage of biomass fuel on-site, therefore delivery from the biomass fuel suppliers will be essentially “just-in-time” prior to utilization in the boiler. Such delivery will be based on contact by the station operating staff. Product delivery will typically be via truck, with material dumping into a contained subgrade, live- bottom hopper(s), from which material is delivered under a metered flow rate to boiler systems. Receiving and material handling systems for rail delivery are also being investigated.

b) Further conceptual design has taken place since the first draft data response to 2- 15(b) submittal was provided. Primary biomass fuel delivery to the NED site will be by truck. Rail delivery is also being examined in concert with discussions with aggregators and processors, and in parallel with feasibility confirmation with BNSF (owner/operator of the rail line adjacent to NED). Biomass fuel delivery will either be by truck or rail receipt to a receiving location adjacent to and north of the NED 3 boiler building, where mechanical handling systems will be utilized to receive and convey the biomass to the CFB boiler. After initial material weighing, the process flow of solid biomass fuel from the point of receipt to discharge into the boiler consists of the following conceptual steps (subject to change in detail design):

1. Initial screening and magnetic separation (magnetic material collected for disposal) of biomass fuel from either delivery source; 2. Conveyance of biomass fuel via “classifier” to multiple day bins in the Biomass Fuel Storage Building (Barn); 3. Classifier segregates wet material (discharge to Barn floor) and oversize material (discharge to grinder/hog) for processing and ground (inactive) storage pile inside the Barn; mobile equipment will be utilized to manage inactive floor storage, to process wet biomass through a proposed rotary drum dryer, and to reclaim biomass from inactive storage and return such via Stamler reclaimer back to the classifier inlet;

Page 6 of 7

Exhibit ___ (RDB-1) Schedule 3

4. Screw augers feed biomass fuel from day bins in the Barn to a flight elevator, which exits the Barn and discharges biomass fuel onto the tripper conveyor in Boiler Building; 5. Tripper conveyor discharges biomass fuel into surge bins, adjacent to boiler; 6. Surge bin feed augers discharge biomass fuel into boiler (using adjustable flow rate and multiple feed ports). . The overall system design basis is predicated on receipt of wood chips that meet a fuel specification prepared to minimize on-site fuel processing. Existing Nelson Dewey space limitations mandate that biomass fuel processing (sizing, shaping, cleaning, drying) take place at the aggregator/processor’s off-site facilities. Because it is anticipated that such processing will not be perfect and that transportation systems may allow moisture intrusion, provisions for limited on-site grinding and drying have been included.

The design basis for all receiving equipment has been based on rapid turnaround of incoming trucks and rail cars as there is limited on-site space for delivery vehicle staging. The combined capacity of the on-site day bins and surge bins is five days worth of material, with supplemental inactive storage possible on the floor of the Biomass Barn. Flow rates associated with all conveying equipment, except for higher rates at truck/rail unloading stations, is 80 tons per hour. Given challenges associated with handling biomass, the bins are typically fitted with “live bottoms” and components such as screw augers are being planned with redundancy where suitable to minimize the potential for forced outages in the face of expected biomass fuel handling challenges. Transfer points and bins will typically be treated with dust collectors and bin vent filters to minimize fugitive dust and fire hazards.

Details on the boiler feed system have not been finalized, as a boiler manufacturer has not been selected and each manufacturer employs specific concepts and systems to best accommodate combustion. Because of bridging concerns and to accommodate flexibility in boiler feed rates, screw augers with flow control (e.g., variable frequency drives) are currently being considered as a means of coarsely adjusting the feed rate to the boiler.

Page 7 of 7

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-17

Data Request No. 2-17:

1.1 Project Description and Overview

1.1.15 Coal, Pet Coke and Biomass Source, Storage and Handling System

(ref. 1-69, 1-73, 1-154, 1-157, 1-158, 1-159, 1-164, 1-165, and 1-178): Provide the wetland delineation needed for DNR to evaluate Alternatives 2A, 2B, and 2C and their related impacts for the new rail line proposed at NED.

Response:

The wetland delineation report was included in the Waterways and Wetlands Permit Application submitted to the WDNR and USACE in February 2007. A revised wetland delineation report will be submitted as Attachment #2 to the revised NED 3 Wis. Stat. § 30.025 permit application. WPL anticipates filing the permit application in early December. WPL is proposing to construct Practicable Alternative 2B (see Response to Data Request 2-31 for an explanation and the revised Practicable Alternative Analysis Table). The proposed layout for Alternative 2B or Alternative 2C will not directly impact the forested floodplain wetlands north of the Stonefield Historic Site or the emergent wetlands located on site adjacent to the railroad tracks. A sheet pile wall is proposed to be installed at or just bluff-side of the delineation boundary of the forested wetlands in Alternative 2B to eliminate impacts to these wetlands. The railroad layout has been reconfigured to avoid the emergent wetlands on site adjacent to the railroad tracks. There are no direct construction-related permanent impacts to wetlands anticipated as part of this project. Approximately 0.01 acres of secondary impacts to wetlands due to shading from the new railroad bridge over unnamed creek are anticipated.

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3 CONFIDENTIAL Attachment

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-18

Data Request No. 2-18:

1.1.15.2 Coal, Pet Coke, and Biomass Source, Storage and Handling Systems

(ref. 1-74, 1-132, 1-133, and 1-149): The response states that the “new mooring location” is in an area “considered poor mussel habitat and appears to support relatively few mussels (0-10/m2).” Given the close proximity to known mussel beds supporting threatened and endangered mussel species, the specific information used by WP&L for the stated mussel habitat quality conclusion must be provided. Additional mussel surveys of the new mooring area may be required, depending on the nature and content of the background information used by WP&L for the analysis. Also document the coordination and interaction between WP&L and the DNR and USFWS regarding the presence of rare mussels at the revised mooring location.

Response:

The referenced responses previously issued by WPL were based on two research reports and mussel transects completed by ESI,1,2 which provided definition of mussel presence in the areas directly in front of, or central to, the existing barge unloader and south of NED in calendar year 2006. The two research reports are attached hereto. These surveys identified the presence of mussels, which have been classified as Federally Endangered, State Endangered, State Threatened, and State Special Concern categories. According to ESI, the new mooring location is presently characterized as having lower river flow rate, likely presence of sedimentation deposits versus preferred gravel/granular bottom, and likely possesses less food stocks than other neighboring locations wherein the mussel population is more robust.

Additional new mussel transects were conducted in July 2007 and a new mussel survey report was issued in August 2007, a copy of which is attached hereto. 3 A final November 2007 mussel assessment is also attached hereto.4

Page 1 of 2

Exhibit ___ (RDB-1) Schedule 3 CONFIDENTIAL Attachment

WPL has had ongoing dialogue with staff from the WDNR, USFWS, and USACE regarding proposed activities that would take place in or along the Mississippi River and the effort to minimize impact on aquatic species. The WDNR has conducted NED site visits to evaluate barge-related concerns, and has been involved along with USFWS in evaluating resource and assessment plans for protecting aquatic species.

References 1. Ecological Specialists, Inc., “Unionid Mussel and Habitat Survey of a Proposed Dredge Site Near Mississippi River Mile 608 (Cassville, Wisconsin)”, October, 2006.

2. Ecological Specialists, Inc., “Unionid Mussel and Habitat Survey of the Mississippi River at a Proposed Barge Expansion Site for Wisconsin Power & Light Company’s Nelson Dewey Generating Station in Cassville, Wisconsin”, January, 2007.

3. Ecological Specialists, Inc., “Survey of Unionid Mussels and Habitat in the Mississippi River Near a Proposed Barge Expansion Site for Wisconsin Power & Light Company’s Nelson Dewey Generating Station in Cassville, Wisconsin – 2007 Study”, August, 2007.

4. Ecological Specialists, Inc., “Assessment of Federal and State Threatened and Endangered Unionid Mussel Species for the Nelson Dewey Generating Station Unit 3 Project at Mississippi River Mile 608 Cassville, Wisconsin,” November 2007.

Page 2 of 2

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-20

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Joe Shefchek Author’s Title: Director – New Generation Planning Author’s Telephone No.: (608) 458-3132 Witness: (If other than Author)

Data Request No. 2-20:

1.1 Project Description and Overview

1.1.15 Coal, Pet Coke and Biomass Source, Storage and Handling System

(ref.1-78 (1.1.15.2)), following up on the response to 1-78): a) Describe the barge unloading equipment and how it would work. b) Explain how on-shore construction methods are better than off-barge methods. c) Explain how siltation impacts are to be minimized through location, sizing, and design. d) Discuss in detail why redesign or augmentation of the existing barge facility cannot be done or considered in lieu of the additional facility that is proposed. e) Contrast, in detail, the necessity of the proposed barge facility expansion against whether smaller scale improvements to the existing facility would accommodate the additional fuel deliveries for NED3.

Response:

a) Barge unloading equipment will likely consist of either elevated mechanical or hydraulic clam shell or continuous bucket elevator unloading equipment. After a loaded barge is positioned along the mooring cells (dock) and attached to the cable positioning system, said barge is moved under the unloader where an operator initiates unloading operations. For clam shell unloaders, the operator will remove barge contents via a large bucket, which is operated via winch on a cantilevered boom over the barge. The material is brought to the shore and the bucket is opened above a hopper, which feeds into a conveyor system. With a continuous bucket unloader, the operator positions a cantilevered bucket elevator within the barge confines and, through maneuvering of the unloader, empties the barge. The bucket unloader discharges barge material directly onto a belt conveyor, which transports the material into the on-site handling Page 1 of 4

Exhibit ___ (RDB-1) Schedule 3

system. After the barge is emptied, the cable positioning system transports the empty barge away from the unloader, the tugboat faces a loaded barge up against the dock, and the unloading process starts again. The NED 3 plant will have the capability of unloading two barges at once, given use of two unloaders in parallel. The tug also moves emptied barges into a fleeting area, where such are lashed to other barges prior to the return trip to the sourcing terminal. Common shipping lanes and fleeting areas used presently for Unit 1 and 2 fuel supply will be utilized into the future. b) On-shore construction methods are often simplified by the efficiencies and safety of personnel and equipment working off of a land base rather than from a boat or barge. Work activities, such as driving sheet pile for cofferdam and pile installation (mooring cells and unloader foundation), filling cells, pouring foundations, and erecting above-water unloader and other superstructures, can all be accomplished from land side with minimal use of barges. Review of the bathymetric data from the Mississippi River in calendar year 2006 indicated a need for limited localized dredging in front of the new unloader, most of which is immediately adjacent to the rip-rap protected shoreline. It is estimated that up to 75% of the dredging work can be accomplished from an on-shore dragline or similar, with the balance completed by a barge-mounted clamshell or similar.

In summary, on-shore construction methods, which have a reduced impact on local aquatic life over barge construction, will be maximized. For the proposed barge unloader foundation and superstructure construction, limited off-shore construction methods will be preceded by measures such as curtain installation to: (1) protect local aquatic life, including local mussel beds; (2) keep fish and other wildlife out of the construction zone; and (3) minimize any resuspension and transport of fine solids from the river bed downstream. c) Silt and sand is deposited in the proposed unloader (mooring) area north of the existing dock because flow rates and water velocity in the area are diminished. This is due to river shape (primary and secondary channels) and configuration of the shoreline. As part of the proposed unloader construction, dredging and shoreline adjustments will be made to increase river flow through the dock area to reduce the possibility for future siltation. NED personnel will monitor river depth to confirm the design over time and will repeat any necessary dredging activity in the future under appropriate permitting. d) Replacement of the undersized existing barge unloader was considered as an alternate to the addition of a second unloader. Such replacement of this 1959- vintage equipment will require significant modification of the existing foundation to provide sufficient unloading capacity with cantilevered equipment, the amount of work and resulting cost is not significantly different from the addition of the second unloader. Alternate addition of a second unloader offers significant redundancy in the event of a malfunction in existing equipment, and its capital cost was found to be only slightly higher than replacing the existing. Another advantage is that the existing unloader can remain in-service during construction of the second unloader and auxiliary equipment (no disruption in

Page 2 of 4

Exhibit ___ (RDB-1) Schedule 3

fuel supply to existing Units 1&2 operations). e) A detailed comparison of replacing the existing unloader (Option 1) versus adding a second unloader (Option 2) was completed, as documented in the following table. Consideration was given to operating staff, physical differences, unloading capabilities, redundancy, capital cost, environmental impact, and other factors. Operating requirements associated with the second unloader (Option 2) will require one additional staff member if the unloaders are operated in parallel. Under Option 2, each unloader will be configured to support material offload and direct fuel flow to either of the Units 1&2 and Unit 3 crusher buildings (assuming additional fuel is needed) or to stock-out and on- site storage; limestone for Unit 3 will not be unloaded by the barge unloaders (rail or truck shipment will be utilized). Under Option 2, the existing unloading equipment will continue to support Units 1&2 operations. Under Option 1, changes to on-site conveying systems, stock-out, reclaim, and mobile equipment plans will be required, and a number of components will have no redundancy in the event of an equipment malfunction. This was judged to be a significant issue, given the increase in material to be offloaded after the addition of NED 3.

From an environmental perspective, little difference was found between the two options. Both options will likely require some preliminary mussel relocation, wildlife separation from the construction zone, and actions during construction to prevent sediment resuspension and transport downstream. Option 2 will require slightly greater dredging and shoreline rework, but the net effect of these actions will be reduced propensity for shoreline erosion in the future. The existing river bank in the area of Option 2 will generally be retained as-is, except at the new barge unloader foundation. As noted in the table below and based on 2006 bathymetric data, the difference in dredging required for Options 1 and 2 there is a difference in amount of dredging but such removed material will be re-used on site as non-structural fill. The current river depth measured in 2006 in the primary construction area of either Option 1 or 2 is in excess of 8 feet.

Barge Unloading Options 1 and 2 - Qualitative Comparison ATTRIBUTE Option 1 Option 2 Cycle/Unloading Time Increased unloading capacity, Potentially faster fleet using upgraded unloader unloading cycle depending on design (e.g., cantilevered whether both unloaders and continuous bucket elevator). barge cable positioning systems are used in parallel.

Redundancy No redundancy, which could Redundant unloading system produce problems during from existing Units 1&2 unloader or discharge unloading system. conveyor forced outage. Units 1&2 and Unit 3 Interconnection occurs at new Cross connect of the existing Material Handling transfer tower where material Units 1&2 Crusher Building

Page 3 of 4

Exhibit ___ (RDB-1) Schedule 3

Interconnection is divided among units or from the new Unit 3 supply directed to stockout. downstream of the unloader

Constructability Construction must be Construction can take place accomplished during the year round. Maximum winter season to avoid construction from shore, or impacts on existing Units 1&2 from a stationary barge operations. Significant positioned between shore and enlargement of existing mooring cells. foundation, with re-use of existing cofferdam shell underneath envisioned. Capital Cost Capital cost estimated at $5.9 Costs include new unloader million. and in-river construction (estimated at $6.6 million). Environmental Impacts Slightly reduced impacts on Three new mooring cells in River (no additional mooring slag slip area, with some cells and reduced dredging at mussel relocation likely. approximately 200 cubic Approximately 2,000 cubic feet). Shoreline rework only yards of river bottom requires at new barge unloader dredging. foundation. Operator Interface Same operating staff as Multiple unloading operations current system (single barge in parallel will increase unloader only). operating staff by one. Barge Handling and Modification (modernization) Two separate barge cable Positioning (Cable of the existing barge cable systems required to handle System) positioning system. two barges simultaneously (additional operator) In-River Construction No increased impact to the Additional mooring cells and and Traffic riverfront footprint. Traffic tie-offs will be needed. pattern will remain the same, Slightly modified traffic but significantly more pattern for tug and barges in frequent deliveries. front of NED given 2 unloaders.

Page 4 of 4

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-21

Data Request No. 2-21:

1.1 Project Description and Overview

1.1.18 Required Permits and Approvals

(ref.1-104 (1.1.18.2)): This item (for Table 17 – State Required Permits and Approvals- NED3 Preferred Site) does not address all of the state required permits and approvals required under Wis. Stat. ch. 30.

Numerous activities associated with developing the NED3 facility fall under the jurisdiction of Wis. Stat. ch. 30, and the implementing Wis. Admin. Codes. Such activities may include: dredging; sediment sampling for dredging projects; miscellaneous structures - shore erosion controls, intake and outfall structures; piers; barge fleeting or holding areas; culverts and bridges; structures on the river bed; grading; ponds; and possibly others, depending on the final design. Some Chapter 30 permits may also become unnecessary, depending on the final design. Please include in Table 17 all applicable state permits and approvals.

Also provide in this application at the appropriate sections, all of the detailed information required by DNR for all applicable permits.

Response:

WPL has submitted to the DNR “one application” for a permit for its proposed utility facility, in lieu of separate applications, in accordance with Wis. Stat. § 30.025(1s)(a). This Wis. Stat. § 30.025 permit application, and any subsequent Wis. Stat. § 30.025 filings, contain the information required by DNR for any required “permit” as defined in Wis. Stat. § 30.025(1b)(b). Wis. Stat. § 30.025 does not require that “all of the detailed information required by DNR for all applicable permits” be included both within the CPCN and the Wis. Stat. § 30.025 application – the statute requires the submission to Page 1 of 4

Exhibit ___ (RDB-1) Schedule 3

the DNR within the Wis. Stat. § 30.025 application of detailed information for the DNR to deem the Wis. Stat. § 30.025 application complete and for the DNR to deem whether the permitting criteria within Wis. Stat. § 30.025(3) are met. Wis. Stat. § 30.025 (1s)(a).

The following table identifies the various Chapter 30 provisions containing the substantive approval criteria applicable to the activities regulated under Wis. Stat. § 30.025. Substantive permitting information required pursuant to applicable DNR Chapter 30 permitting regulations will be included in an updated NED 3 Wis. Stat. § 30.025 Permit Application to be submitted to the DNR in mid- to late - November.

As indicated within the updated NED 3 Wis. Stat. § 30.025 Permit Application, the following activities are subject to Chapter 30 regulation: construction of a bridge across waterways, dredging, grading, filling and soil disturbance activities on the bank of a navigable water, construction of a storm water pond, placement of an outfall structure, stream bank erosion control, and placement of miscellaneous structures on the river bed (three mooring cells and new barge unloader foundation).and temporary barge unloading structure, as well as applicable water quality certification needed for state and federal waterway permits. The updated NED 3 Wis. Stat. § 30.025 Permit Application also contains information necessary for the federal permits needed for dredging, installation of structures within/over the Mississippi River and for the installation of the lateral collector well.

1.1.18.2 State Permits

Table 17 lists the state required permits and approvals for NED 3. It is possible that some of the substantive criteria listed below associated with the Wis. Stat. § 30.025 permit application may not be required, or additional provisions will need to be met, based upon final plans for fuel delivery by rail and/or barge.

Table 17 State Required Permits and Approvals – NED 3 Preferred Site

Contact Agency Planned Activity Type of Approval Status (Name & Phone No.) Public Service Construction of large electric CPCN (Wis. Stat. §196.491(3)) Pending William Commission of generating facility Fannucchi Wisconsin (608) 267-3594 Department of Construction and operation Construction and operating permits Filed with Revisions to be Steve Dunn Natural of new source of air (Wis. Admin. Code Chs. Natural Filed (608) 267-0566 Resources emissions Resources (NR) 405 through 407) Department of Required for issuance of Section 401 Water Quality Filed with Revisions to be Dave Siebert Natural USACE Section 404/10 Certification contained in Wis. Stat. Filed (608) 264-6048 Resources permits unless waived by § 30.025 Permit Application. WDNR

Department of Construction of bridge across Chapter 30 (Navigable Waters, Filed with Revisions to be Dave Siebert Natural waterways; dredging; Harbors and Navigation) Permit: Filed (608) 264-6048 Resources grading, filling and soil 30.123, 30.20, 30.19, 30.12, contained disturbance activities on the in Wis. Stat. § 30.025 Permit bank of a navigable water; Application, as necessary. construction of a storm water pond; placement of an outfall structure; stream bank erosion control; placement of miscellaneous structures on a river bed. Page 2 of 4

Exhibit ___ (RDB-1) Schedule 3

Contact Agency Planned Activity Type of Approval Status (Name & Phone No.) Department of Discharge of wastewater for Modification/update of existing Filed with Revisions to be Duane Natural industrial activity WPDES permit number WI-0002381- Filed Schuettpelz Resources 05-0 (608) 266-0156 Department of Disposal of ash at WPL’s Modification of existing “Plan of To be filed Adam Hogan Natural COL’s landfill ash disposal Operation” to accept Project ash at (608) 275-3292 Resources site COL Landfill ash disposal site #111049180 (License No. 3025). Operation of a landfill (Wis. Admin. Code Ch. NR 506).

Department of Erosion control plan for land Stormwater discharge permit (Wis. Filed with Revisions to be Eric Rortvedt Natural disturbance during Admin. Code Ch. NR 216) (Notice of Filed (608) 273-5612 Resources construction Intent) – Erosion Control Plan and Stormwater Management Plan, contained in Wis. Stat. § 30.025 Permit Application. Department of High capacity dewatering Construction and operating permits Filed with Revisions to be Bill Furbish Natural well for industrial activity (Wis. Admin. Code §§ NR Filed (608) 266-9264 Resources 812.09(4)(a) & (b))

Department of Prior department approval is High Capacity Water Source Filed with Revisions to be Bill Furbish Natural necessary for the Determination and/or Well Installation Filed (608) 266-9264 Resources construction, reconstruction, (Wis. Admin. Code NR 812.09(a) & or operation of a high (b)) and locational variance approvals capacity well system or as necessary wastewater treatment plant well system

Department of Hydrostatic test water or Wisconsin Pollution Discharge Filed with Revisions to be Duane Natural water supply system water Elimination System (WPDES) permit Filed Schuettpelz Resources (Wis. Stats. Ch. 283) (608) 266-0156 Department of Modification of the water “Notice of Planned Change” for To be filed Duane Natural treatment facility industrial wastewater treatment Schuettpelz Resources facilities (Wis. Admin. Code Ch. NR (608) 266-0156 108) Department of Modification of existing Storm water discharge permit (Wis. To be filed Eric Rortvedt Natural industrial stormwater Admin. Code Ch. NR 216)-Storm (608) 273-5612 Resources pollution prevention plan Water Pollution Prevention Plan during operation Department of Pit/trench dewatering Covered under WPDES stormwater Filed with Revisions to be Eric Rortvedt Natural construction permit for construction Filed (608) 273-5612 Resources activities at the site Department of Storage of coal combustion Approval under Wis. Admin. Code § Filed with Revisions to be Adam Hogan Natural byproducts NR 502.05(3)(I) Filed (608) 275-3292 Resources Department of Required under Wisconsin River Basin Water Loss Approval Filed with Revisions to be Duane Natural Administrative Code NR 142 Filed Schuettpelz Resources Wisconsin Water (608) 266-0156 Management and Conservation before beginning a new withdrawal or increasing the amount of an existing withdrawal

Department of Various land disturbance Bureau of Endangered Resources Pending Shari Koslowsky Natural construction activities that Clearance (608) 261-4382 Resources may be subject to Wis. Stat. § 29.604(6r). Department of Installation of related Approval of safety mechanisms and To be filed Jim Quast Commerce equipment for CFB Unit plans (Wis. Stats. § 101.17) (608) 266-9292

Department of Construction of all buildings Approval of plans and specifications To be filed Jim Quast Commerce and structures (Wis. Stats. § 101.02) (608) 266-9292 Department of Installation of fuel or Approval of plans and specifications To be filed Sheldon Schall Commerce lubricating oil storage tanks (Wis. Stats. § 101.09) (608) 266-7874

Page 3 of 4

Exhibit ___ (RDB-1) Schedule 3

Department of Installation of dust filtering Approval of plans and specifications To be filed Jim Quast Commerce and HVAC equipment (Wis. Stats. § 101.12) (608) 266-9292 Department of Stormwater Construction Stormwater Construction Notice of To be filed Robert Kanter Commerce Intent (608) 261-6541 Department of Construction of tall Approval of plans and specifications To be filed Gary Dikkers Transportation structures affecting (Wis. Stats. § 114.135, Wis. Admin. (608) 267-5018 Wisconsin airspace Code Ch. Trans 56)

Department of Delivery of large/heavy Over Heavy Vehicles Permit To be filed WI State Dept. Transportation components Transportation Permits – Oversize – Overweight (608) 266-7320 Wisconsin Approval of Archeological (Wis. Stats. § 44.40) Filed Chip Harry Historical Surveys Brown Society (608) 264-6508 Office of Changes to road crossings Application under Wis. Stat.§ 191.01 To be filed Tom Running Commission of (608) 261-8221 Railroad

Construction of NED 3, including the railroad relocation project north of NED, will not require any fill material to be placed in wetlands and, thus, will not need state or Federal approvals for grading and filling within wetlands. WPL is evaluating whether potential WPDES approvals are needed for dredging operations WPL expects to have this evaluation completed and applicable information included within the revised Wis. Stat. § 30.025 Permit Application to be submitted in mid- to late- November.

Wis. Admin. Code NR § 327, barge fleeting in navigable waterways, is not applicable to NED 3. This Code provision regulates “barge fleeting,” which is defined as “the temporary storage of barges and the disassembly and assembly of barge tows.” Wis. Admin. Code NR § 327.03(2). “It does not include the temporary mooring of line tows or loading or unloading operations.” Id. (emphasis added). The purpose of adding additional barge unloading and mooring capacity to WPL’s existing barge unloading facility is to provide a place for barges operated by an independent contractor to temporarily moor near NED 3 in order to perform loading or unloading operations specifically for NED 3. These loading and unloading activities are specifically excluded from Wis. Admin. Code NR § 327.

The May, 2007 CPCN Application, however, contained several figures that identified an area designated as a “Potential Future Barge Fleeting Area (Alliant).” For example, see “Future Barge Docketing Patterns at NED 3 Site,” at NED 93-94. Current plans do not include a new barge fleeting area as part of NED 3. The relevant figures have been revised to remove the barge fleeting area and new figures will be submitted with the revised Wis. Stat. § 30.025 permit application to be submitted in mid- to late- November.

Page 4 of 4

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-22

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Ken Cackoski Author’s Title: Special Projects Manager Author’s Telephone No.: (319)786-7245 Witness: (If other than Author)

Data Request No. 2-22:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.1 Plant and Facility Maps

(ref.1-109 (1.2.1.2, pp. 138 ff)): It is not clear how much of the existing right-of-way crosses agricultural versus forested land and how much of the new right-of-way would cross agricultural versus forested land. Clarify the proportions.

Response:

Below is a table that provides land use information of the conceptual 161kv line route for the transmission line that will connect Nelson Dewey Substation to the Iowa transmission system.

Line Length R-O-W State Land Use 0.3 miles Existing Wisconsin Woodland 1.3 miles Existing Wisconsin Commercial/Developed 0.3 miles Existing Wisconsin/Iowa Mississippi River 2.0 miles Existing Iowa Woodland-lowland 3.0 miles New Iowa Woodland-highland 4.5 miles New Iowa Agricultural 3.5 miles Existing Iowa Agricultural

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-23

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Dennis McFarland Author’s Title: Sr. Projects Engineer Author’s Telephone No.: (608)458-5142 Witness: (If other than Author)

Data Request No. 2-23:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.2 Natural Resource Maps

(ref.1-110 (1.2.2.2)): The map provided for this item does not include all the requested information. Provide the map with the requested information, including rail line construction staging and laydown areas, and potential erosion-sedimentation places.

Response:

See Attachment PSC 2-23.

Sheet pile for the track subgrade construction will be stockpiled on the plant site and distributed along the rail road alignment. Fill material for the subgrade construction will be delivered by truck to the fill areas, so no space will be required for any material stockpile.

The track materials will be stockpiled on the plant site and distributed along the rail road alignment as the grading and subballast placement are completed. The subballast will be delivered by truck to the subgrade, so no space will be required for any material stockpile. The ballast will be delivered by rail and distributed along the rail road alignment from the ballast cars.

Construction equipment parked and serviced in the work areas along the rail road alignment.

Silt fence and other stormwater best management practice devices will be installed at the downslope sides of all disturbed areas along the rail road alignment.

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Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-23

RELCOATED COUNTY NOTE: SILT FENCE AND OTHER STORMWATER MANAGEMENT HIGHWAY VV BMP'S SHALL BE INSTALLED AT THE DOWNSLOPE SIDE OF ALL DISTURBED AREAS.

RELOCATED BNSF MAIN LINE TRACK

UNLOADED UNIT TRAIN PARALLEL INDUSTRIAL TRACK

TRACK SERVICE ROAD

LOADED UNIT TRAIN PARALLEL INDUSTRIAL TRACK LAYDOWN AREA

SOURCE: AERIAL PHOTO - NAIP 2005 IMAGERY

NORTH

2000' 0' 2000' Plant Rail Plan SCALE IN FEET NED 3 Preferred Site Wisconsin Power and Light Company Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-24

Data Request No. 2-24:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.12 Construction Areas

(ref. 1-120 (1.2.12)): How will the current landfill capacity at Columbia be maintained with the revised design footprint to accommodate the proposed cooling towers?

Response:

The proposed cooling towers for COL 3 (alternate) would displace approximately 677,000 cubic yards of the existing landfill at the Columbia Energy Center. This would reduce the estimated remaining capacity (as of the end of 2006) from 4,900,000 cubic yards to 4,223,000 cubic yards.

If the existing units at COL continue to place 15,000 tons per year, or 12,500 cubic yards, into the landfill and COL 3 (alternate) places all of its coal combustion products (bottom ash, econ ash, fly ash, and wet FGD solids) into the landfill, there will be 125,000 tons, equivalent to 104,167 cubic yards, placed in the landfill per year starting in 2012. The construction of the proposed cooling towers would result in a minimum remaining capacity 40 years. This is a worst-case scenario as COL has an extensive history of beneficial reuse of coal combustion products.

Page 1 of 1 Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-25

Data Request No. 2-25:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.13 Soils

(ref.1-123 (1.2.13.3, p. 167)): Two copies of Wis. Stat. § 30.025 permit applications from WP&L are required to be filed with the Commission. As soon as the revised permit applications are submitted to DNR, submit two hard copies of the applications to the PSC.

Response:

Two (2) copies of the revised NED 3 Wis Stat 30.025 permit application will be provided for PSC review when they are filed with the WDNR. As requested, WPL filed a draft copy of the text for the NED 3 Wis Stat 30.025 permit application with the PSC on October 16, 2007. WPL anticipates filing the permit application in early December 2007.

Page 1 of 1 Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-25

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: January 3, 2008 Author: John Oswald Author’s Title: Environmental Lead – Wisconsin Baseload Author’s Telephone No.: (608) 458-4882 Witness: (If other than Author)

Data Request No. 2-25:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.13 Soils

Response:

On December 17, 2007 WPL filed two hard copies of the confidential version of WPL’s Wis. Stat. § 30.025 Permit Application (“Application”), two hard copies of the public version of the Application and a CD containing the same. The public version of the Application and the confidential portions of the Application (e.g., portions of § 8 of the main Application text and appendices D, H and K) were electronically filed on ERF.

Page 1 of 1 Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-26

Data Request No. 2-26:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.16 Endangered, Threatened and Special Concern Species and Communities

(ref. 1-129, 1-130, 1-131 (1.2.1.6) and 1-156 (1.2.18.2.5)): DNR correspondence cited in data request 1-130 indicates that survey protocols/plans should be submitted prior to initiating surveys. The response provided implies that this will not occur and DNR will only be provided with the results of the surveys or assessments. This is not acceptable and presents a risk of project delays if information was collected or evaluated in a manner that is unacceptable to DNR. Update the status of the surveys being done for the rare birds, the slender glass lizard, and Blanding’s turtle, and the habitat assessment of the southern dry forest and disturbed old field communities that would be removed for the construction of the plant at Columbia. Document the consultation between WP&L and the appropriate staff at DNR to confirm the method, timing, and locations of the surveys. Provide all information resulting from the surveys and the subsequent evaluation of potential impacts.

Provide the results of any fish surveys completed by WP&L at either the NED or COL sites for wastewater or water use permits. DNR has more recent survey data through 2006 indicating the presence of rare fish species near the NED facility. Discuss the potential for rare fish species to occur at the proposed barge facility and impacts that may result during construction or operation of the facility.

Response:

WPL certainly did not intend to imply in its Response to Data Request 1-130 that a work plan or survey protocols and methodologies would not be submitted to the DNR. Confusion may have been caused by two statements in the Response to Data Request Page 1 of 3

Exhibit ___ (RDB-1) Schedule 3

1-130. One statement indicated that “WPL has commenced the preparation of an ERP” and the second statement indicated that “Results of specific surveys will be included in the final ERP”. To further clarify, there are essentially two components of an Endangered Resource Plan (ERP). The first component of the ERP involves the preparation of an ERP “Work Plan” that determines the species for which surveys are recommended and the proposed survey dates, protocols and methodologies. The second component of the ERP is the ERP “Report,” which includes a summary and evaluation of the survey results and an action plan to protect species as necessary during project construction activities. Both of these ERP documents are typically submitted to the DNR. WPL and its consultant, Natural Resources Consulting, Inc. (NRC), have been in regular communication with the DNR Office of Energy (OE) staff regarding the species survey protocols and the ERP during the past few months and following the receipt of the February 28, 2007 DNR letter.

WPL submitted a Confidential ERP work plan for NED 3 to the DNR on June 4, 2007. It contains information pertaining to the presence or potential presence of listed species, their associated preferred habitats, whether surveys are needed for each listed species and the status of such surveys. WPL is currently compiling the substantive information obtained from the completed surveys and will submit the results of those surveys to the DNR. Individual species survey results for the Bald Eagle, the Red Shouldered Hawk and the Cricket frog are being provided as separate reports to the DNR. Additional reports will be provided as they become available. The individual species survey results will then be compiled into a single ERP report that evaluates the potential impacts to these species related to the project. The report will be submitted to the DNR. In addition, a Biological Assessment (“BA”) will also be prepared that evaluates the potential impacts of the project upon the federally-listed species, including potential impacts from additional barge unloading and mooring capacity, additional barge traffic and construction and maintenance activities. The BA will form the basis of any agreement concerning translocation of federal and state-listed mussels.

WPL is also currently preparing an ERP work plan for COL 3. The work plan will be provided under separate cover to the DNR. Similar to the NED 3 ERP work plan submitted to the DNR, the COL 3 ERP will contain information pertaining to the presence or potential presence of listed species at COL 3 and their associated preferred habitats, whether surveys are needed for each listed species and the status of such surveys. Surveys for selected species will commence upon DNR review of the ERP work plan or as soon as August and September, 2007. Once the surveys are completed, the information will be compiled and submitted to the DNR.

A Section 316(b) Impingement Mortality Characterization Study was performed for purposes of WPL’s NED Units 1 and 2 WPDES permit renewal. This impingement study was developed in conjunction with DNR WPDES permit staff and will be submitted to DNR WPDES staff for purposes of NED Units 1 and 2 Clean Water Act (“CWA”) §316(b) compliance. Because NED 3 will utilize water from the installation of a lateral collector well adjacent to and underneath the Mississippi River, NED 3 is not subject to CWA § 316(b) and, thus, the impingement study is not relevant to NED 3 WPDES permitting.

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Exhibit ___ (RDB-1) Schedule 3

The Impingement Mortality Characterization Study contains a summary of specific fish species impinged at NED Units 1 and 2 during the study period. Of the 45 fish species identified over the study period’s 29 separate sampling events, no threatened or endangered fish species were impinged, dead or alive, and only one state species of special concern (pugnose minnow) was impinged. These results suggest a lack of threatened or endangered fish species in the general vicinity of the existing barge facility. The existing barge facility, in combination with proposed expansion of the barge facility, will be utilized to handle the increase in barges moored for unloading at the NED 3 site.

WPL has scheduled an additional survey for federal and state-listed mussels in the location of the existing barge unloading facility and in the area of the proposed barge facility expansion to the north of the existing barge facility. This survey will also include a habitat assessment for federal and state-listed fish species and potential for the existence of spawning areas in the area of the proposed barge expansion. The fish habitat data that will be collected during the 2007 survey will be discussed either in the Mussel Survey Report or in the NED 3 ERP or BA. The 2007 habitat survey data in combination with the Impingement Study data will be evaluated for impacts associated with the NED 3 barge expansion. In addition, upon receipt of DNR 2006 fish data referenced in the data request, WPL will review and incorporate that information/data as appropriate into the ERP or BA for NED 3.

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Exhibit ___ (RDB-1) Schedule 3 Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-27

Data Request No. 2-27:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.17 Air Emissions and DNR Air Quality Permit

(ref. 1-136 (1.2.17)): Provide the following follow-up information to the PSC related to the DNR air pollution permits for the project at each site.

a) Provide any updated permit information related to NOx control and SO2 control, including changes in proposed control systems or BACT, or emission levels and resulting emissions in tons per year. b) Provide any updated permit information related to NAAQS and PSD compliance resulting from changes in a). c) Provide any updated information about HAPs emissions, including mercury emissions, that would result from changes in a). d) Provide any updated information on CO2 and other GHG emissions, in CO2 equivalents, that would result from the changes in a). e) Provide a copy of any updated information on biofuels that is provided to DNR for the air permit work. f) If PM2.5 regulation goes into effect before the air permit process is completed, DNR may need to enforce it for this project. Provide any updated BACT analyses and emission and compliance information related to updated DNR permit or regulatory requirements.

Response:

a) Based on the current permit revisions, there are no planned changes to the emission controls that were presented in the February 7, 2007 PSD air permit applications for NED 3 or COL 3. However, WPL has further evaluated fuels for the NED 3 project. The NED 3 air permit application presented information based on a fuel flexibility scenario that included 99% of all fuels available in the United States. This was one of the criteria in developing the NED 3 CFB boiler

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Exhibit ___ (RDB-1) Schedule 3 SO2 emission limits. WPL determined that this range of fuels was overly expansive and has since brought in the bookend for the upper range of high sulfur fuels to be considered for NED 3. This means that the boiler outlet SO2 concentration would likely change. WPL is still working out the details of the revised air permit application related to the change in fuels.

• Since the NED 3 air permit application was submitted, and since the last data request response was filed, WPL’s EPC contractor has determined that there will be changes to several of the emission sources at NED 3 as follows:

• the auxiliary boiler will no longer be required • the barge unloader will be located at the north end of the facility • the coal stack out and conveyance configuration has been optimized resulting in one coal stack out not being needed (3 were originally proposed) • a biomass rail car and truck unloading and storage facility, with particulate control devices, is now included (the permit application indicated a storage pile) • the limestone storage building will be enclosed (the permit application indicated it would be covered) • the limestone and lime handling configuration has been optimized resulting in a change in the storage vessels, the removal of the limestone reclaim tunnel and two limestone crusher-dryers.

• WPL is working on finalizing these changes and the evaluation that will be part of the final air permit application. While these changes are not for significant emission sources, such as the CFB boiler, it appears that they will result in emission changes for SO2, CO, NOx, and VOCs. For example, removing the auxiliary boiler will result in lower annual emissions of NOx by about 5 tons, CO by 4.1 tons, VOCs by 2.7 tons, and SO2 by 0.2 tons. PM and PM10 emissions are also expected to decrease as a result of the removal of the auxiliary boiler but these decreases will likely be offset by additional material handling emission sources associated with biomass and changes in conveyance system throughputs.

• There are no planned changes to COL 3 that would impact emissions. b) WPL believes that the results of the revised NAAQS and PSD modeling that is being performed for NED 3 as a result of changes discussed in the above response will not dramatically change from the results presented in the February 7, 2007 air permit application. There are no changes planned for COL 3 and, therefore, there are no anticipated changes to the modeling results for that site. c) As indicated in the response to a) above, the changes to the NED 3 facility layout and design are not for significant emission sources. While there are expected to be emission reductions for primary pollutants, which appear to be at least measurable in tons, any reductions in HAPs associated with the changes will be very small in comparison, and only associated with changes to combustion sources. For example, the removal of the auxiliary boiler will result in a reduction in mercury of approximately 0.32 pounds and 56 pounds of H2SO4, as well as

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Exhibit ___ (RDB-1) Schedule 3 very small amounts of other HAPs.

HAPS emissions presented in the February 7, 2007 air permit application were based on PRB coal as the worst case fuel since the quantity of PRB coal needed to achieve the hourly heat input is greater than those fuels with higher heat value. This assumption has not changed as a result of the planned changes to the site layout and design.

There are no planned changes to COL 3 that would impact HAPs emissions. d) The removal of the auxiliary boiler at NED 3 will result in a decrease in GHG emissions as follows: • 9,151 tons of CO2 • 0.045 tons of N20 (14 tons CO2 Equivalent) • 0.0213 tons of CH4 (0.45 tons CO2 Equivalent)

WPL does not believe that there will be any other significant reductions in CO2 or other GHG emissions from the changes discussed above in a).

WPL has performed an evaluation of GHG emissions associated with the combustion of biomass fuels in the NED 3 CFB boiler. In the CPCN application, WPL provided GHG emissions associated with the combustion of 80% PRB coal and 20% petroleum coke. If the blend of fuel considers the benefit of burning 10% biomass fuel, then the CO2 emissions would be reduced by the percentage of coal (or petroleum coke) that is not burned. This occurs because the benefit of biomass toward CO2 emissions is based on the closed cycle concept of the carbon in biomass. Biomass absorbs CO2 from the atmosphere, retaining the carbon and releasing oxygen. As biomass is combusted CO2 is released. The cycle is completed as the CO2 is again absorbed by the biomass. The amount of CO2 that is reduced through the biomass cycle is based on how much fossil fuel the biomass replaces. In the case of NED 3, a 10% replacement of subbituminous coal is equal to approximately 260,000 tons of CO2 reduced annually.

There are no planned changes to COL 3 that would impact CO2 emissions. e) WPL will be working with the WDNR to specifically address the ability to test fire several biomass fuels at NED 3, including woody biomass and switchgrass, which were included as fuels in the original air permit application, and densified corn stover and mixed grass (hay, straw, etc) that will be new fuels listed in the revised air permit application. WPL is evaluating additional biomass fuels that may be included in the revised air permit application. f) WPL had discussed the issue of PM2.5 regulatory activity with the WDNR, and it was determined that WPL would develop a PM2.5 BACT that would be submitted as part of a revision to the air permit application at some point. While not required until the State develops specific rules adopting requirements for PM2.5, and with the State planning on having standards in place mid-2008, WPL feels that it is in a good position to be prepared for this change and that it will not impact the planned controls or permit schedule. Page 3 of 4

Exhibit ___ (RDB-1) Schedule 3

WPL will also be conducting PM2.5 dispersion modeling, which we have also discussed with the WDNR. On September 12, 2007, the EPA published a proposed rule that explains options for developing increments and significant impacts levels for demonstrating compliance with PM2.5 NAAQS and PSD. It will be some time before this proposed rule becomes final. Meanwhile, WPL will be working with the WDNR to understand what modeling can be performed in the interim to develop an understanding of the project’s impact to NAAQS and PSD.

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Exhibit ___ (RDB-1) Schedule 3 CONFIDENTIAL Attachments

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-28

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Kirby Letheby and John Oswald Author’s Title: Team Lead – New Generation Author: John Oswald Author’s Title: Environmental Lead – Wisconsin Baseload Author’s Telephone No.: 608-458-3276/608-458-4882 Witness: (If other than Author)

Data Request No. 2-28 Supplemental:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.18 Waterway and Wetlands

(ref. 1.2.18.1.2, p. 208-209): Construction would impact 2.5 acres of river bed, but details are not sufficient for analysis. Respond to the following: a) Provide all foundation sizes, including dimensions and volumes. b) What is the permanent impact to the river bed? c) How would foundations be constructed, and what would be the construction sequence? d) How much area of the river would be converted to barge mooring, line tows, and loading and unloading operations? e) What water quality protection measures would be implemented during construction? f) Would there be dredged material? If so, respond to the following: 1) Where would it be disposed? 2) What would the contaminant levels be associated with disturbed sediments and/or dredged materials associated with all activities occurring within the floodplain? 3) Provide permit application information and plans for the proposed dredging, pursuant to Wis. Adm. Code ch. NR 345 and Wis. Stat. § 30.20; see: http://www.dnr.state.wi.us/org/water/fhp/waterway/dredging.shtml g) Provide information and plans for the barge tower unloader foundation and the mooring foundations that is sufficient to meet requirements for application for

Page 1 of 9 Exhibit ___ (RDB-1) Schedule 3 CONFIDENTIAL Attachments

permit; see http://www.dnr.state.wi.us/org/water/fhp/waterway/piers.shtml or http://www.dnr.state.wi.us/org/water/fhp/waterway/miscellaneous.shtml h) Provide information and plans for clear span bridge across Dewey Creek that is sufficient to meet requirements for application for bridge permit. See Clear Span Bridge General Permit Packet R1-07 and Application for Bridges Form 3500-53F (R 1/2002) at http://www.dnr.state.wi.us/org/water/fhp/waterway/ i) Provide information and plans for construction of the stormwater pond that is sufficient to meet requirements for application for a pond permit; see http://www.dnr.state.wi.us/org/water/fhp/waterway/ponds.htm j) Provide information and plans for land disturbance and grading on the “bank” that is sufficient to meet requirements for application for a grading permit; see http://www.dnr.state.wi.us/org/water/fhp/waterway/grading.shtml k) Provide information and plans for construction of the intake and outfall structures along the Mississippi River, sufficient to meet requirements for application for permit; see http://www.dnr.state.wi.us/org/water/fhp/waterway/intakeoutfall.shtml#step3 l) Provide information and plans for rip rap, sheet piling, and other possible shore erosion control structures for the NED 3 site and the railroad tracks that is sufficient to meet requirements for application for permit; see http://www.dnr.state.wi.us/org/water/fhp/waterway/miscellaneous.shtml

Response:

a) Provide all foundation sizes, including dimensions and volumes.

The new moorings are estimated to have similar diameters as the existing (18 feet, 8 inches in diameter) subject to final detail design; the depth and volume of excavations within the river bed have not been determined at this time, but the existing cells are 55 feet long and penetrate approximately 20 feet into the river bed. A reinforced concrete topping slab approximately 3 feet thick will be placed at the top of the cells and founded on gravel. The elevated barge unloader foundation will be approximately 50 feet wide and 60 feet long and will extend into the river approximately 50 feet to align with the outer cell (barge) line.

b) What is the permanent impact to the river bed?

Pending final design, there will be an estimated 1.2 acres of work area with a river dredge area of approximately .5 acres, three 18 foot 6 inch moorings, and one 50 foot by 60 foot foundation. Based on a review of current and historical bathymetric maps, the dredging will restore the area to the depths present when the NED Units 1&2 were constructed. The area is currently utilized for the maneuvering of barges for Units 1&2.

c) How would foundations be constructed, and what would be the construction sequence?

Page 2 of 9 Exhibit ___ (RDB-1) Schedule 3 CONFIDENTIAL Attachments

River-bank construction methods will be used for all superstructure construction. This construction is preferentially used over on-barge methods of construction for safety and efficiency reasons. In-river construction will include installation of driven sheet pile cofferdam and piles to simplify needs for stability and structural support and minimize environmental impacts. The in-river footprint will be limited to the mooring cells and barge unloader foundation placed between two of the cells. The existing river course will essentially remain intact and usable by river traffic during construction. The existing riprap protected bank will not be significantly altered. The only bank modification will be in the vicinity of the barge unloader foundation, where existing riprap will be removed and replaced with the poured concrete mat extending into the river behind the mooring cells for the unloader foundation. The elevated unloader foundation will consist of driven steel or concrete piles, installed by both a pile driving rig with extended boom located on the bank and barge-mounted pile driving rig (outermost piles). Reinforced concrete pile caps and unloader mat foundation will require installation from both a temporary barge and the river bank (all concrete pumped into foundation formwork from the river bank). The unloader superstructure will then be built on top of this pile-supported foundation from land access. Use of driven piles will minimize how much dredging is required for the unloader foundation and to provide structural support for significant live loads produced by the unloader when in-service. Final design will confirm construction methods required; the foundation construction may be aided by installation of permanent sheeting piling on one or more sides.

Construction work from tow boat/barge combination or vessel will be limited to piling installation. After cellular cofferdam installation, lashed-in-place barges may also be used to access the cells for gravel placement or improved access. However, current plans call for this effort to be primarily via on-bank crane and clamshell bucket or similar system. The cells will be filled with clean gravel from local sources for improved stability. Barges may also be used to install formwork for the elevated bucket unloader pile caps and mat foundation. After dewatering and tamping, gravel will be placed inside the cells and compacted in lifts. The permanent cofferdam cells will be driven by a barge-mounted pile driving rig. The balance of the work will be managed from the river bank via temporary staging for personnel safety and security reasons.

Construction sequence information is:

Freshwater mussels within the work area will be relocated, if necessary, following proven mussel relocation procedures, and a suitable location, whether at the downstream bed or at an Essential Habitat Area defined by the U.S. Fish and Wildlife Service, will be selected in consultation with involved authorities;

Page 3 of 9 Exhibit ___ (RDB-1) Schedule 3 CONFIDENTIAL Attachments

A temporary sediment curtain will be installed in the Mississippi River surrounding the work area to prevent re-suspension of solids and transport downstream during dredging and foundation work. This sediment curtain will also serve the dual purpose of keeping fish and other aquatic wildlife out of the construction zone and potential harm;

Staking of all new construction by assigned coordinates;

Removal of on-site brush (if needed) to allow access to the work area, and extension of roadway and temporary power supply to same;

Dredging of the river bottom in the work area;

Construction of the new barge unloader and mooring cells by:

Installation of sheet pile coffer dams and piles;

Placement of gravel fill;

Installation of formwork;

Pouring of concrete;

Removal of formwork;

Building of the barge unloader superstructure on top of the pile supported foundation from land access.

d) How much area of the river would be converted to barge mooring, line tows, and loading and unloading operations?

Loading and unloading operations will occur at both the existing unloader and the new unloader associated with the upgraded/expanded barge unloading facility. Barges will be moored at the barge unloading facility during the unloading process. Three new additional moorings will be installed immediately to the North of the existing moorings. This area (from shore out about 150 feet and for a distance of about 350 feet upstream of the existing moorings or approximately 1.2 acres) is currently utilized for barge activity for NED Units 1 & 2. The size of the moorings and foundation located in this area are described in the above response (a). e) What water quality protection measures would be implemented during construction?

Page 4 of 9 Exhibit ___ (RDB-1) Schedule 3 CONFIDENTIAL Attachments

Erosion control best management practices are provided in the construction erosion sediment control plan and the revised Wis. Stat. § 30.025 permit application. In general, erosion control measures will meet or exceed the technical standards for erosion control approved by DNR pursuant to Wis. Admin. Code NR 151. As indicated above, a temporary sediment curtain will be used to prevent re-suspension of solids and their transport downstream during dredging and the construction of foundations for the three barge moorings and new barge unloader. All staging areas for construction activities associated with the new barge unloading area will be equipped with siltation fencing around the perimeter to mitigate fugitive dust and erosion into the Mississippi River. The existing riprap and contours along the river bank will be retained where possible. Any area where topsoil is exposed during construction shall be seeded and mulched or rip rapped to stabilize disturbed areas and prevent soils from being eroded and washed into the waterway. These provisions will prevent sediment resuspension and downstream deposition from occurring.

Although WPL has assigned BMPs to planned construction and post- construction activities, these BMPs may require updating in appropriate documents (e.g. the Erosion Control Plan) based upon issuance of the Wis. Stat. 30.025 permit. f) Would there be dredged material? If so, respond to the following:

1) Where would it be disposed?

The current design will require the dredging of material within the Mississippi River. To preserve a 12-foot depth against normal pool level, the amount of sediment that will be dredged from the Mississippi River is estimated to be approximately less than 2,000 cubic yards. To the extent possible, dredged material is anticipated to be used on-site in upland locations as fill material.

2) What would the contaminant levels be associated with disturbed sediments and/or dredged materials associated with all activities occurring within the floodplain?

WPL does not anticipate that disturbed sediments and/or dredged materials will be contaminated. WPL has, in the past, worked with the USACE to utilize dredged river sediments as part of managing the NED ash landfill. These materials were collected by the USACE under its agreement for managing river sediments. Based upon the results of the 2006 dredging efforts near the existing unloader, the dredged material (sediment) to be removed is expected to be primarily sand and silt, with some organics and gravel.

Page 5 of 9 Exhibit ___ (RDB-1) Schedule 3 CONFIDENTIAL Attachments

3) Provide permit application information and plans for the proposed dredging, pursuant to Wis. Adm. Code ch. NR 345 and Wis. Stat. § 30.20; see: http://www.dnr.state.wi.us/org/water/fhp/waterway/dredging.shtml

The revised Draft NED 3 Wis. Stat. § 30.025 permit application, Section 9.4.2, addresses dredging activities. A copy of the October 16, 2007 Draft permit application was provided to the PSC and DNR on October 16 in response to a request by Staff for the most current draft so that Staff could review its scope, and that copy is attached hereto as Attachment 2-28(1). WPL has been working to finalize the permit application since October 16, and some more current information is contained in the November 2007 Mussel Assessment, which is being provided with the Response to Data Request 2-18. The information in the Mussel Assessment should be considered to be more current than information contained in the October 16 Draft permit application. A final Wis. Stat. § 30.025 permit application is anticipated to be filed in early December 2007. See Response to Data Request 2-25. g) Provide information and plans for the barge tower unloader foundation and the mooring foundations that is sufficient to meet requirements for application for permit; see http://www.dnr.state.wi.us/org/water/fhp/waterway/piers.shtml or http://www.dnr.state.wi.us/org/water/fhp/waterway/miscellaneous.shtml

The revised Draft NED 3 Wis. Stat. § 30.025 permit application, Section 9.4.7, addresses information concerning the barge tower unloader foundation and mooring foundations. A copy of the October 16, 2007 Draft permit application was provided to the PSC and DNR on October 16 in response to a request by Staff for the most current draft so that Staff could review its scope, and that copy is attached hereto as Attachment 2-28(1). WPL has been working to finalize the permit application since October 16, and some more current information is contained in the November 2007 Mussel Assessment, which is being provided with the Response to Data Request 2-18. The information in the Mussel Assessment should be considered to be more current than information contained in the October 16 Draft permit application. A final Wis. Stat. § 30.025 permit application is anticipated to be filed in early December 2007. See Response to Data Request 2-25. h) Provide information and plans for clear span bridge across Dewey Creek that is sufficient to meet requirements for application for bridge permit. See Clear Span Bridge General Permit Packet R1-07 and Application for Bridges Form 3500-53F (R 1/2002) at http://www.dnr.state.wi.us/org/water/fhp/waterway/

The revised Draft NED 3 Wis. Stat. § 30.025 permit application, Section 9.4.1, addresses the bridge over Dewey Creek and unnamed creek. Both bridges are currently planned to be pre-cast concrete slab girders placed on top of concrete pile caps and pilings. A copy of the October 16, 2007 Draft permit

Page 6 of 9 Exhibit ___ (RDB-1) Schedule 3 CONFIDENTIAL Attachments

application was provided to the PSC and DNR on October 16 in response to a request by Staff for the most current draft so that Staff could review its scope, and that copy is attached hereto as Attachment 2-28(1). WPL has been working to finalize the permit application since October 16, and some more current information is contained in the November 2007 Mussel Assessment, which is being provided with the Response to Data Request 2-18. The information in the Mussel Assessment should be considered to be more current than information contained in the October 16 Draft permit application. A final Wis. Stat. § 30.025 permit application is anticipated to be filed in early December 2007. See Response to Data Request 2-25. i) Provide information and plans for construction of the stormwater pond that is sufficient to meet requirements for application for a pond permit; see http://www.dnr.state.wi.us/org/water/fhp/waterway/ponds.htm

The revised Draft NED 3 Wis. Stat. § 30.025 permit application, Section 9.4.4, addresses the stormwater pond. A copy of the October 16, 2007 Draft permit application was provided to the PSC and DNR on October 16 in response to a request by Staff for the most current draft so that Staff could review its scope, and that copy is attached hereto as Attachment 2-28(1). WPL has been working to finalize the permit application since October 16, and some more current information is contained in the November 2007 Mussel Assessment, which is being provided with the Response to Data Request 2-18. The information in the Mussel Assessment should be considered to be more current than information contained in the October 16 Draft permit application. A final Wis. Stat. § 30.025 permit application is anticipated to be filed in early December 2007. See Response to Data Request 2-25. j) Provide information and plans for land disturbance and grading on the “bank” that is sufficient to meet requirements for application for a grading permit; see http://www.dnr.state.wi.us/org/water/fhp/waterway/grading.shtml

The revised Draft NED 3 Wis. Stat. § 30.025 permit application, Section 9.4.3, addresses grading activities on the bank. A copy of the October 16, 2007 Draft permit application was provided to the PSC and DNR on October 16 in response to a request by Staff for the most current draft so that Staff could review its scope, and that copy is attached hereto as Attachment 2-28(1). WPL has been working to finalize the permit application since October 16, and some more current information is contained in the November 2007 Mussel Assessment, which is being provided with the Response to Data Request 2- 18. The information in the Mussel Assessment should be considered to be more current than information contained in the October 16 Draft permit application. A final Wis. Stat. § 30.025 permit application is anticipated to be filed in early December 2007. See Response to Data Request 2-25.

Page 7 of 9 Exhibit ___ (RDB-1) Schedule 3 CONFIDENTIAL Attachments

k) Provide information and plans for construction of the intake and outfall structures along the Mississippi River, sufficient to meet requirements for application for permit; see http://www.dnr.state.wi.us/org/water/fhp/waterway/intakeoutfall.shtml#step3

The revised Draft NED 3 Wis. Stat. § 30.025 permit application, Section 9.4.5, addresses the placement of an outfall structure along the Mississippi River for the proposed storm water detention pond. There is no new intake structure associated with NED 3. A copy of the October 16, 2007 Draft permit application was provided to the PSC and DNR on October 16 in response to a request by Staff for the most current draft so that Staff could review its scope, and that copy is attached hereto as Attachment 2-28(1). WPL has been working to finalize the permit application since October 16, and some more current information is contained in the November 2007 Mussel Assessment, which is being provided with the Response to Data Request 2-18. The information in the Mussel Assessment should be considered to be more current than information contained in the October 16 Draft permit application. A final Wis. Stat. § 30.025 permit application is anticipated to be filed in early December 2007. See Response to Data Request 2-25. l) Provide information and plans for rip rap, sheet piling, and other possible shore erosion control structures for the NED 3 site and the railroad tracks that is sufficient to meet requirements for application for permit; see http://www.dnr.state.wi.us/org/water/fhp/waterway/miscellaneous.shtml

Based on information WPL and its consultants have obtained from the USACE Rock Island District, the Ordinary High Water Mark (OHWM) is estimated to occur at elevations approximately 4 feet above the mean pool elevation of 603 feet MSL. A physically observable feature representing the OWHM is present near the shore of the Mississippi River south of the boat landing. WPL does not intend to disturb the area below the OHWM defined by this feature south of the boat landing. The shoreline adjacent to where barge construction would occur is currently buffered by rip-rap to the top of the bank. The location of the OHWM in the floodplain forest adjacent to the proposed railroad industrial track and sheet pile wall is based on the elevations provided by the USACE Rock Island. Three drawings are attached that depict the OHWM in the vicinity of the site generally, and more specifically near the proposed sheet pile wall (Alternative 2B) and the toe of slope of the fill (Alternative 2A). The overview (general) figure depicts the OHWM elevations on various river mile section lines from River Mile 607 to River Mile 611.2. The drawings depicting the sheet pile wall location and the fill toe of slope location show various low – point spot elevations along both of these features. In addition, the OHWM elevations are shown on the river mile section lines that bisect the sheet pile wall and the fill toe of slope. The OHWM elevations along the sheet pile wall and/or the fill toe of slope are below the low-point spot elevations. Therefore

Page 8 of 9 Exhibit ___ (RDB-1) Schedule 3 CONFIDENTIAL Attachments

the sheet pile wall location (Alternative 2B) is situated above the OHWM based on USACE data. Additionally, the WDNR also evaluated the OHWM in the general vicinity of the NED during a field visit in September 2007. Based on a benchmark reference point provided to WPL by the WDNR, and surveyed by WPL consultants, the general OHWM as determined by the WDNR is 607.80 feet MSL. As a result, the sheet pile wall will be above the OHWM as determined by the WDNR.

The revised Draft NED 3 Wis. Stat. § 30.025 permit application, Section 9.4.6, addresses stream bank erosion control associated with rip rap, and other applicable shore erosion control structures for the NED 3 site. The sheet pile wall associated with the railroad tracks is above the OHWM and, thus, not subject to Wis. Stat. § 30.12 requirements for erosion control, but is subject to Wis. Stat. § 30.19 requirements for grading on the bank. A copy of the October 16, 2007 Draft permit application was provided to the PSC and DNR on October 16 in response to a request by Staff for the most current draft so that Staff could review its scope, and that copy is attached hereto as Attachment 2-28(1). WPL has been working to finalize the permit application since October 16, and some more current information is contained in the November 2007 Mussel Assessment, which is being provided with the Response to Data Request 2-18. The information in the Mussel Assessment should be considered to be more current than information contained in the October 16 Draft permit application. A final Wis. Stat. § 30.025 permit application is anticipated to be filed in early December 2007. See Response to Data Request 2-25.

Page 9 of 9 Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-29

Data Request No. 2-29:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.18 Waterway and Wetlands

(ref. 1-150 (1.2.18.1.2)): The response contends that river recreation will not be impacted by the construction of the proposed new barge docking facility, but only from the point of view of the power plant. What is the current level of recreational boating use at or near the proposed barge site and proposed barge tugboat paths for approach to and departure from the site? What would be the impacts of the increased barge traffic on ferry traffic, sport and commercial fishing levels, and summer recreational use in the area? Provide information from research done in the Illinois and Mississippi Rivers on commercial barge and tug effects on sediment resuspension, pressure changes, and so forth, to aid with navigational and environmental habitat impact analyses for both the immediate vicinity and the surrounding area.

Response:

Pool No. 11 of the Mississippi River is located between Lock and Dam No. 10 (river mile 615) and No. 11 (river mile 483) and is lined by the state of Iowa on the west bank and Wisconsin on the east bank. This pool does not have significant human population along its banks (less than 5,000 people in adjoining villages and towns, aside from Dubuque, Iowa at Dam No. 10). As a result, recreation traffic on the pool is not as great as in other Upper Mississippi River (UMR) pools. NED is located approximately ½ mile upstream of the Village of Cassville (population 1,045) at river mile 608.

Few statistics are maintained on actual boat traffic on the Mississippi River, whether recreational or other, aside from those by the U.S. Army Corps of Engineers for traffic passing through the Lock and Dams. Recreational traffic volume confined within the pool itself without Lock and Dam passage, including the Village of Cassville public ferry movement, is not measured. Page 1 of 6

Exhibit ___ (RDB-1) Schedule 3

Statistics Review Recent-year data on Pool 11 river traffic is summarized in the following table based on U.S. Army Corps of Engineers data for Lock and Dam 11. Since calendar year 2000, the total number of lock cuts, vessels, and barges in this specific pool has diminished by between 20 and 25 percent. Vessel counts are the sum of upstream and downstream vessels traveling through Lock and Dam No. 11.

Navigational Data for UMR Pool 11 Lockages and Shipping (USACE-OMNI Reports) Data/Year 2000 2001 2002 2003 2004 2005 2006 Total 8155 6281 7166 7015 6523 7319 6214 Vessels (#) Commercial 2014 1534 1970 1880 1547 1618 1641 Vessels (Tugs) (#) Total 20030 16037 20316 17690 14559 14578 15422 Barges (#) Recreational 6141 4747 5196 5135 4976 5701 4573 and Other Vessels (#)

In terms of traffic volume represented by these statistics, a peak increase in number of fleet deliveries and barges of 116 fleet operations and 950 barge loads is expected per year for the proposed NED 3 plant. Simple addition of 232 vessels (116 total fleet round trips) to the 2006 total commercial vessel count of 1641 vessels listed above results in a total of 1873 vessels which is slightly higher than the average number of commercial vessels considered in the 2000 to 2006 period but less than total commercial vessels observed in 2000, 2002, and 2003.

Local effects of this increased tug and barge traffic in front of NED, estimated for both the existing Units 1&2 and proposed NED 3 needs, is provided in the following table, based on tug and barge routes and numbering shown in the attached figure.

Page 2 of 6

Exhibit ___ (RDB-1) Schedule 3

Estimated Changes in Local NED River Traffic Route No. Current Route Future Route Commentary Traffic (Units Traffic 1&2) (Combined Units 1, 2 & 3) 1 8 20 Coke deliveries (from upstream) 2 64 168 Coal (and future limestone) deliveries (from downstream) 3 65 162 Pet coke barge from local Holding Area across River to NED Station 4 485 1338 Local tug assistance at NED dock area (limited barge positioning/facing operations) 5 550 1500 Empty barge move to fleeting area 6A 8 20 Empty fleet return (upstream) 6B 64 168 Empty fleet return (downstream)

Route numbers 1 and 2 represent fleet deliveries from existing river terminals up and downstream of NED to staging areas in front of NED, and route numbers 6A and 6B represent empty barge returns (round trips) to the source terminals. This increased traffic represented by Routes 1, 2, 6A, and 6B will add to other boats utilizing the navigation channel in Pool 11. In the case of Route No. 1, this increase results in 34 more uses of Lock and Dam Nos. 3 through 10. In the case of Route No. 2, this increase results in 208 more uses of Lock and Dam No. 11. Both of these increases are minor in terms of total lock and dam utilization, and both are viewed to have insignificant influences on congestion at the locks as compared to recreational vessels.

Route No. 3 consists of lateral crosses of the navigational channel of a tug and singular loaded barge. The route is across relatively deep water and, given individual barge movement, results in far less energy transfer from tug propeller into wash effects. Route Nos. 4 and 5 are immediately in front of NED, and similarly involve tug maneuvering of single loaded and unloaded barges from staging area to dock or dock to fleeting area. These are characterized by short paths (Route No. 4 is less than 300 feet and Route 5 is less than 500 feet), and low energy transfer from tug propeller into wash effects. The affected pool area is or will be deeper than 12 feet in these areas, providing at least three feet clearance from barge bottom and an estimated five foot clearance with the tug propeller.

Local Traffic The Village of Cassville ferry operates Wednesday through Sunday from the end of May through the end of September, with partial schedules in May and October, between the hours of operation of 9:00am to 9:00pm (weather and river conditions permitting). The ferry crosses the River perpendicular to the main navigational branch of the river to the Iowa side (Great River Road connection for transported vehicles). The tug/barge routes associated with NED that cross the ferry route are Routes 1, 2, 3, and 6B (see the barge traffic figure submitted in section 1.1.15.2 along with pages NED-92 and NED-93 of the updated May 2007 CPCN Application) . WPL schedules barge deliveries

Page 3 of 6

Exhibit ___ (RDB-1) Schedule 3 to NED at times to avoid ferry traffic.

NED is located immediately downstream of the confluence of the main navigation channel, Cassville slough, and secondary channel running east of existing Island No. 192. Review of the Iowa DNR maps of the pool and U.S. Fish and Wildlife Service data on the McGregor District found few other recreational access points in the vicinity of the Station:

Pool 11 Landing or Access River State Mile

Guttenberg Landing 614.5 IA

Schleichers Landing 613.0 WI

Turkey River Landing 607.8 IA

Wisconsin Power and Light Landing ** 607.7 WI

Cassville Public Access 606.4 WI

Eagles Roost Resort Landing 605.8 WI

Lowells Landing 603.6 IA

Bertom Lake Access 601.7 WI

Anthony’s Resort / Waupeton Landing 600.0 IA

McCartney Lake Access 598.5 WI

Lynn Hollow Public Access 597 WI

Finley's Landing 595.8 IA

Potosi Public Access 592.5 WI

Grant River Recreation Area 592.5 WI

Mud Lake / Arrowhead Marina 589.5 IA

Mud Lake Recreation Area 589.3 IA

Sunfish Lake 583.3 IA

(** NOTE: This is a private landing that will no longer be in use during/after construction of NED 3 )

Page 4 of 6

Exhibit ___ (RDB-1) Schedule 3

As a result, most of the recreational traffic confined within the pool is associated with random fishing, sightseeing, and pleasure craft, most of which is not regularly scheduled. As a result, impacts of the limited increase in fleet traffic are difficult to assess but are believed to be minimal. As previously indicated in table form, the greatest increase in tug traffic is immediately in front of NED which is not considered a focal point for recreational purposes. In summary, most recreational traffic for which statistics exist primarily travels through upstream and downstream locks and dams and is associated with traffic through the pool on the main navigational channel. The increase in fleeting operations associated with material deliveries for the proposed NED 3 is viewed to be minimal given current limited recreational traffic in this pool.

Additional information about the volume and effects of commercial and recreational vessel and barge traffic for the upper Mississippi River is available from the U.S. Army Corps of Engineers (USACE), U.S. Geologic Survey’s Upper Midwest Environmental Sciences Center (USGS MESC), and other governmental and research agencies.

An example of these study findings is shown here in the summary introduction of the ENV report 31, September 2000. Physiological Effects on Freshwater Mussels of Intermittent Exposure to Physical Effects of Navigation Traffic by Barry Payne, Andrew Miller, and Larry Shaffer

The following references were used in preparing this response:

1. Minnesota Department of Natural Resources, Mississippi River Landscape Team, “Shoreline and Water Quality Impacts From Recreational Boating on the Mississippi River”, May, 2004.

2. “Assessment of Potential Effects of Increased Commercial Navigation on the Fishes of the Upper Mississippi River System”, USGS MESC (Principal Investigator: S. Gutreuter), 2001.

Page 5 of 6

Exhibit ___ (RDB-1) Schedule 3

3. Wilcox, D. (USACE), “Effects of Recreational Boating on the Upper Mississippi River System”, Technical Working Group on Effects of Recreational Boating, St. Paul District, 2001.

4. Johnson, S., Recreational Boating Impact Investigations, Upper Mississippi River System, Pool 4, Red Wing, Minnesota”, Minnesota Department of Natural Resources, February, 1994.

5. USACE, Navigation Data Center, Waterborne Commerce Statistics Center, 2007 (statistics for Mississippi River lock and dam passages).

6. Payne, B., Miller, A. and Shaffer, L., “Physiological Effects on Freshwater Mussels of Intermittent Exposure to Physical Effects of Navigation Traffic,” ENV Report 31, September 2006 (http://www.mvr.usace.army.mil/UMRS/NESP/).

Page 6 of 6

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-30

Data Request No. 2-30:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.18 Waterway and Wetlands

(ref.1-151 (1.2.18.1.2, p. 210)): Provide the well diagram showing the location of the well relative to existing land cover and the position of the laterals relative to the depth of the alluvial aquifer and the Mississippi River, said to be attached to this response. Provide the PSC with two copies of the High Capacity Well Application submitted to DNR in July 2006 and any subsequent updates to that application.

Response:

Attached to this data response as Attachment PSC 2-30A is a well diagram for the lateral collector well to be constructed for NED 3 and, as Attachment PSC 2-30B, the High Capacity Well Application for the lateral collector well submitted to the WDNR on July 26, 2006.

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3 Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-31

Data Request No. 2-31:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.18 Waterway and Wetlands

(ref. 1-156 and 1-162 (1.2.18.2.5, p. 224)): The PSC needs an indication that the proposed power plant site is permittable. Provide the documentation that the proposed practicable alternatives analysis and its conclusions are acceptable to DNR and the Army Corps of Engineers.

Response:

The proposed site is permittable. WPL has continued to work on its site layout design and practicable alternatives analysis since it refiled its CPCN Application with its prior Responses to the Commission’s incompleteness questions included. WPL has now developed a site layout design that eliminates any permanent wetland impacts to the forested wetlands north of NED for the rail road track relocation project and to the emergent wetlands in the NED on-site footprint.

WPL’s current practicable alternatives are described in the attached Practicable Rail Delivery Alternative Analysis (“PRDAA”), Attachment PSC 2-31(1). WPL’s preference is Alternative No. 2B. WPL will build two new main line tracks east and parallel to the existing BNSF tracks north of NED and reposition the existing BNSF tracks to serve as WPL’s industrial tracks. Alternative No. 2B involves relocation of portions of County Highway VV toward the adjacent bluff (i.e., away from the Mississippi River) to provide room for the new main line tracks. Construction will include installation of a sheet pile retaining wall on the river side, but out of the forested wetlands as shown on the attached drawing (Attachment PSC 2-31(2)). There will be no requirement to purchase any Nelson Dewey State Park (“NDSP”) land, nor will there be any impact to the stone fence on the bluff land adjacent to Highway VV. WPL will also install a barrier between

Page 1 of 4

Exhibit ___ (RDB-1) Schedule 3

the two new main line tracks and Highway VV where necessary. This alternative continues to require purchase of two parcels of private land, and WPL is currently in discussions with the landowners.

Alternative No. 2B will eliminate the impact to what was previously estimated to be less than 2.5 acres of forested wetland within the Mississippi River floodplain. WPL’s forecasted construction methods are not intended to have any temporary impact to forested wetlands. It is anticipated that installation of the sheet pile retaining wall will take place from the Highway VV side and require no equipment to be positioned in the forested wetlands. In the event of any minor, temporary impact to forested wetlands in the area of the sheet pile retaining wall during construction, the area will be reclaimed and returned to existing condition to the extent reasonably practicable. The location of the sheet pile wall and the wetland delineation line are shown on the attached drawing (Attachment PSC 2-31(2)). A CD with a GIS file of the drawing is also included with this response.

In addition, the sheet pile retaining wall will not “seriously disrupt, [or] eliminate, animal movements between wetland and upland for an approximate mile.” Certain wildlife species use both wetland and upland habitats throughout the year, while others are found only in wetland or in upland habitats, but not in both. Therefore, not all species present in the project area will be moving between the two habitats. In addition, the abrupt change in habitat type, from floodplain forest to upland forest located on a steep bluff, and the separation of the two habitat types (by existing railroad tracks and a county trunk highway), already limits the movement of many of the smaller terrestrial animals. In all likelihood, the majority of the species that are moving between the two habitats are edge species that are using the wooded edge along the railroad tracks and County Highway VV and the disturbed area located between the tracks and the road.

Nevertheless, construction of the sheet pile wall would affect the movement of some species of wildlife in the project area, specifically smaller, less mobile species with small home ranges, such as small mammals and some of the amphibians and snakes. The individuals affected the most would likely be those whose home range is near the middle of the wall, since presumably those individuals living near the ends of the wall could just go around the ends. Likewise, larger mammals, such as deer and raccoons, would in all likelihood walk along the wall until they came to the end, and then also pass around the ends of the wall. In time, the larger animals would probably adjust their travel routes to compensate for the wall. Bird species should be relatively unaffected by the wall.

Regarding wetland functions and values, specifically the wildlife habitat function, the wall would not preclude the wetland from serving as wildlife habitat. As stated previously, the wall might affect the movement of some individuals of certain species; but overall, wildlife would still be able to utilize the wetland as habitat. Thus, the sheet pile retaining wall “will not result in significant adverse [secondary] impacts to wetland functional values, significant adverse impacts to water quality or other significant adverse environmental consequences.” Wis. Admin. Code § NR 103.08(4).

Page 2 of 4

Exhibit ___ (RDB-1) Schedule 3

Normal water levels and conditions would not bring water wave actions and currents into contact with the sheet pile wall causing erosion concerns. There are, however, certain water levels and water conditions that have potential for erosion impacts to wetland soils at or near the sheet pile wall. These water levels and water conditions include the ordinary high water mark level and the 100-year flood plain level along with current velocities and wave actions from river flow, river vessel traffic and wind. Based upon information and interpretation of the Mississippi River ordinary high water mark in the immediate region of this project, as provided by the USACE Rock Island District, the ordinary high water mark lies out towards the river channel and is away from the sheet pile wall so that these water level conditions will not cause erosion at the sheet pile wall. Additionally, the WDNR also evaluated the OHWM in the general vicinity of the NED during a field visit in September 2007. Based on a benchmark reference point provided to WPL by the WDNR, and surveyed by WPL consultants, the general OHWM as determined by the WDNR is 607.80 feet MSL. As a result, the sheet pile wall will be above the OHWM as determined by the WDNR.

The 100 year flood elevation along the sheet pile wall varies from approximately EL. 621 to EL. 622, with the top of the sheet pile wall at approximately EL. 623. During certain flood conditions, the river level can be elevated as high as the sheet pile wall. The sheet pile wall will help protect the track fill from erosion by the flood waters.

In the specific region of the Mississippi River floodplain where the proposed sheet pile wall is to be constructed, some of the erosion concerns associated with high flood levels could be wave actions and flow velocities. The typical causes of wave actions and flow velocities in this area of the Mississippi River are the river current flow, river vessel traffic and wind. The river channel and vessel traffic are, on average, more than 1,000 feet away from the proposed sheet pile wall. The area between the river channel and the sheet pile wall is mainly comprised of forested wetlands that are fairly dense with trees and vegetation. Due to the distance between the proposed sheet pile wall and existing river channel and the defusing effects on the current by the existing vegetation within the forested wetlands, the velocity of the water current and the wave actions from river flows and vessel traffic will not cause any material erosion of wetland soils at the sheet pile wall during ordinary high water flows. Even during periods of flooding (100- year flooding or worse), the velocity of the river current in the overbank area where the wetlands are located should be attenuated such that the flooding event should not result in any material erosion of wetlands soils adjacent to the sheet pile wall. Likewise, the same attenuating effects by the trees and vegetation in the forested wetlands will reduce any wave action impacts in the area of the sheet pile wall such that there should be no material erosion of wetland soils. In addition, during 100-year flood events, vessel traffic would likely be significantly reduced.

Alternative No. 2B also eliminates what was previously estimated to be approximately 1.0 acres of impact to emergent wetlands on-site. WPL has reconfigured the projected on-site track to eliminate all permanent wetland impacts west of Furnace Branch.

The cost of WPL’s Initial Project Design of $15,600,000 (see PRDAA, Attachment 2- 31(1)) was included in the requested Approved Amount for NED 3 in the CPCN

Page 3 of 4

Exhibit ___ (RDB-1) Schedule 3

Application.1 The forecasted cost for Alternative No. 2B is currently $23,000,000. Accordingly, WPL’s Approved Amount request for NED 3 has increased by $7,400,000 for the new practicable alternative for the railroad relocation project. This amount and any further cost updates based on market conditions and any other current cost information will be included as part of WPL’s testimony regarding project costs.

WPL met with Staff from the DNR, USACE on July 20, 2007 to verify WPL’s wetland delineation in the forested wetlands north of NED. The purpose was to verify with the involved regulatory agencies that Alternative No. 2B is acceptable and will not result in any permanent impacts to forested wetlands north of NED or to wetlands contained within the on-site footprint.

Alternative No. 2A is WPL’s practicable alternative to Alternative No. 2B. Alternative No. 2A also involves building two new main line tracks east and parallel to the existing tracks and repositioning the existing main line tracks to serve as WPL’s industrial tracks. It involves relocation of County Highway VV toward the adjacent bluff (i.e., away from the Mississippi River) to provide room for the new main line tracks. Alternative No. 2A does not include installation of a sheet pile retaining wall on the river side. Instead, it will involve filling and grading a strip of land in, and on the edge of, the forested wetland totaling approximately 2.5 acres. A barrier wall would be installed between the newly constructed main line tracks and Highway VV when necessary. There would be no requirement to purchase any NDSP land, nor would there be any impact to the stone fence on the bluff land adjacent to Highway VV. Like Alternative No. 2B, Alternative No. 2A requires purchase of two parcels of private land, and WPL is currently in discussions with the landowners. Also like Alternative No. 2B, this alternative eliminates the previously estimated approximately 1.6 acres of impact to emergent wetlands on-site. WPL has reconfigured the projected on-site track to eliminate alternative wetland impacts west of Furnace Branch.

The projected cost for Alternative No. 2A is $19,000,000, which would result in an increase to the Approved Amount requested in the CPCN Application for NED 3 of $3,400,000. Although Alternative No. 2B exceeds the projected cost of Alternative No. 2A by approximately $4,000,000, it is preferable from a construction perspective as a means of controlling wetland impacts. The retaining wall will be installed immediately adjacent to the wetlands and the location and amount of the fill needed to relocate the existing main line tracks will be controlled through placement of the fill against the retaining wall away from the wetlands. In contrast, it is not possible to predict in advance the precise amount of direct wetland impacts that will result from filling in the wetlands to create a slope rising to the grade level where the industrial tracks will be located. While WPL is reasonably confident that only a narrow strip of land totaling no more than 2.5 acres of wetlands will be impacted, and that the wetlands in such narrow strip are lesser quality than the wetlands closer to the river, the actual impacts cannot be determined until after construction.

1 Previously, the $15,600,000 estimate was mistakenly stated to be $11,400,000. The $11,400,000 was from a later analysis. The $15,600.00 was the number included in the Approved Amount requested in the CPCN Application.

Page 4 of 4

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-31(2) Docket No. 6680-CE-170 Wisconsin Power and Light Company Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-31(2) Docket No. 6680-CE-170 Wisconsin Power and Light Company Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-31(2) Docket No. 6680-CE-170 Wisconsin Power and Light Company Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-31(2) Docket No. 6680-CE-170 Wisconsin Power and Light Company

15' 15' MINIMUM Exhibit ___ (RDB-1) Schedule 3

Attachment PSC 2-31(1) Docket No. 6680-CE-170 Wisconsin Power and Light Company

Practicable Rail Delivery Alternative Analysis

Initial Project Design Potential Practicable Alternative Potential Parcticable Alternative Current Project Design Potential Practicable Alternative Alternatives Determined Not To Be Practicable Analysis Alternative No. 1 (Initial Alternative No. 2 Alternative No. 2A Alternative No. 2B Alternative No. 2C Alternative No. 3 Alternative No. 4 Alternative No. 5 Alternative No. 6 Alternative No. 7 Alternative No. 8 Factor Project Design) Build two new parallel industrial Build two new main line tracks east and parallel Build two new main line tracks east and parallel Build two new main line tracks east and Build two new main line tracks east and parallel Build on-site ladder tracks Build two new parallel Build new parallel industrial Same as Alternative #1 Build one new parallel Build coal unloading tracks on fill using BNSF property to the existing tracks and reposition the existing to the existing tracks and reposition the existing parallel to the existing tracks and reposition to the existing tracks. Leave the existing and split delivered unit train industrial tracks on BNSF tracks (one or two) between (Initial Project Design), industrial track on BNSF facilities and required north of the Stonefield grade main line tracks to serve as industrial tracks. main line tracks to serve as industrial tracks. the existing main line tracks to serve as riverside track at its current location and into multiple sections on property south of Stonefield the existing main line tracks except build the parallel property south of the industrial track(s) adjacent crossing and riverside of the Hwy VV to be moved landside to provide room for Involves minor relocation of Hwy VV to be moved industrial tracks. Involves minor relocation reposition the existing bluffside track to obtain NED site directly from BNSF grade crossing and and Hwy VV, on BNSF industrial tracks on a Stoneman Power Plant with to existing railroad on the existing BNSF main line. Service new main line tracks. Install barrier between landside to provide room for new main line ofHwy VV to be moved landside to provide required spacing to serve as industrial tracks. main line tracks. riverside of the south- property north of Stonefield ballasted deck bridge new ladder track and coal west side of the Mississippi road included. tracks & Hwy VV where necessary. Minimal tracks. Does not include installation of sheet pile room for new main line tracks. This Does not include installation of sheet pile bound main track. Service grade crossing. Service instead of on fill. unloading facilities on the River. Build coal conveyor service road included. Reconfigure on-site track retaining wall on riverside, with no requirements alternative includes installation of sheet pile retaining wall on riverside. Involves relocation to road included. road included. Cassville Municipal Airport across the river to NED. to eliminate wetland impacts west of Furnace to purchase park land or impact rock wall. Install retaining wall on riverside, with no major portions of Hwy VV to provide room for property. Service road Branch. (See Alternatives 2A, 2B & 2C for further barrier between tracks & Hwy VV where requirements to purchase park land or impact new main line tracks. Requires purchasing park included. details). necessary. Minimal service road included. rock wall. Install barrier between tracks & Hwy land with construction impacts to the bluff lands Reconfigure on-site track to eliminate wetland VV where necessary. Minimal service road on the land side of Hwy VV and impacts to the impacts west of Furnace Branch. included. Reconfigure on-site track to rock wall. Install barrier between tracks & Hwy eliminate wetland impacts west of Furnace VV where necessary. Minimal service road Branch. included. Reconfigure on-site track to eliminate wetland impacts west of Furnace Branch.

BNSF Design, Operational, and NO - The train would block NO - The coal cars would NO - The train would block Safety Acceptability the main line track while it have to cross the main line the main line track while it was being moved to and from tracks to get to and from was being moved to and from YES Yes Yes Yes Yes the ladder tracks. Yes NED. YES the ladder tracks. N/A Use BNSF property for new tracks. Potential for Requires considerable land Nelson Dewey State Park and/or private land to be Use BNSF property and on west side of Mississippi Off-Site Land req'd for relocation of Hwy VV. Section 4(f) or 6(f) Use BNSF property. Requires two parcels of private Cassville Municipal Airport River (in Iowa) for tracks, Requirements may be applicable (depends on final track Use BNSF property. Requires two parcels of private Use BNSF property. Requires two parcels of land and public land (Nelson Dewey State Park) for property. Also requires land unloading facilities, and Use BNSF property alignment). See Alternatives 2A, 2B & 2C. land for Hwy VV relocation. private land for Hwy VV relocation. Hwy VV relocation. None Use BNSF property Use BNSF property Use BNSF property for conveyor to NED. conveyor 1 - E. Crawford St. (entrance Off-Site Grade to Jack Oak Road) in Crossing Impacts 1 - Stonefield Village 1 - Stonefield Village 1 - Stonefield Village 1 - Stonefield Village 1 - Stonefield Village None 1 - Wyota St. in Cassville 1 - Stonefield Village 1 - Stonefield Village Cassville Unknown No impacts on the forested wetland within the Mississippi Approximately 1.0 acres of River floodplain or the mixed Approximately 1.0 acres of mixed mixed emergent and forested emergent and forested Wetland Impacts emergent and forested wetland west wetland west of Furnace wetland west of Furnace of Furnace Branch and 8.9 acres of Ranges from less than 2.5 acres down to zero Approximately 1.0 acres of Approximately 3 acres of Approximately 1.0 acres of Branch and 5.2 acres of Branch; however, unknown forested wetlands within the acres of forested wetlands within the Mississippi mixed emergent and forested mixed emergent and forested mixed emergent and forested forested wetlands within the impacts on other wetlands Unknown - likely major Mississippi River floodplain north of River floodplain (depending on final track Less than 2.5 acres of forested wetland within the Zero (0.0) acres of forested wetland within the Zero (0.0) acres of forested wetland within the wetland west of Furnace wetlands east and west of wetland west of Furnace Mississippi River floodplain outside of the proposed impacts on Iowa side of Stonefield Village. alignment). See Alternatives 2A, 2B & 2C. Mississippi River floodplain. Mississippi River floodplain. Mississippi River floodplain. Branch Furnace Branch Branch north of Stonefield Village. project area Mississippi River Operational YES - Reduced unit train YES - Coal unloading facility YES - Coal unloading facility Impacts to NED NONE NONE NONE NONE NONE delivery capability. NONE NONE NONE would not be on NED site. would not be on NED site. Off-site fugitive and point Off-site fugitive and point Air Impacts Base Case Base Case Base Case Base Case Base Case Base Case Base Case Base Case Base Case source PM10/PM emissions source PM10/PM emissions Dewey Creek crossing and unnamed creek crossing Dewey Creek crossing and unnamed creek crossing Dewey Creek crossing and unnamed creek Dewey Creek crossing and unnamed creek crossing Mississippi River (conveyor Waterway Impacts Dewey Creek crossing (1.5 miles north of Dewey Creek) (1.5 miles north of Dewey Creek) crossing (1.5 miles north of Dewey Creek) (1.5 miles north of Dewey Creek) NONE Furnace Creek crossing Dewey Creek crossing Dewey Creek crossing NONE bridge) Currently under WDNR and Currently under WDNR and Currently under WDNR and Currently under WDNR and Threatened & Currently under WDNR and the the USFWS review. WPL is the USFWS review. WPL is the USFWS review. WPL is the USFWS review. WPL is Endangered USFWS review. WPL is currently Currently under WDNR and the USFWS review. currently preparing a currently preparing a currently preparing a currently preparing a Species Impacts preparing a Biological Assessment Currently under WDNR and the USFWS review. Currently under WDNR and the USFWS review. WPL is currently preparing a Biological Currently under WDNR and the USFWS review. Biological Assessment and Biological Assessment and Biological Assessment and Biological Assessment and and Endangered Resource Plan for WPL is currently preparing a Biological Assessment WPL is currently preparing a Biological Assessment Assessment and Endangered Resource Plan for WPL is currently preparing a Biological Assessment Endangered Resource Plan Endangered Resource Plan Endangered Resource Plan Endangered Resource Plan agency review. and Endangered Resource Plan for agency review. and Endangered Resource Plan for agency review. agency review. and Endangered Resource Plan for agency review. for agency review. for agency review. for agency review. for agency review. Unknown Unknown Other Environmental & PENDING - Up to approx. 1500 ft (see Alternatives Development of new off-site Cultural Resource 2A, 2B & 2C) of the historic stone fence parallel to YES - Approx. 1500 ft of the historic stone fence Modification to existing landfill coal yard and associated Impact NONE Hwy VV in NDSP. NONE NONE parallel to Hwy VV in NDSP NONE NONE NONE NONE at Stoneman Power Plant impacts in Iowa

Noise from switching cars and from conveyor to NED. Cassville Village Some blockage of grade Impacts crossing at Crawford Street Noise from switching cars (Jack Oak Road). Requires and some blocking of grade closing of airport for coal NONE NONE NONE NONE NONE NONE crossing at Wyota Street. NONE NONE unloading facilities. NONE Estimated Construction Cost (Does not include wetland mitigation Up to $36,400,000 maximum (depending on final costs) $15,600,000 track alignment - See Alternatives 2A, 2B & 2C) $19,000,000 $23,000,000 $32,000,000 $4,900,000 $6,700,000 $7,000,000 $45,800,000 $24,700,000 $63,000,000

Zero acres of wetland impact. Involves relocation of Significant community Hwy VV into NDSP (as well as onto private land impacts (airport closure, This alternative can provide considerable reduction Wetland impact reduced to less that 2.5 acres of north of NDSP) with significant impact on portions of blocked crossing, noise). Exceptionally high costs and of wetland impacts, <2.5 acres for Alternative 2A forested wetland (N. of Stonefield Village) and zero the historic stone fence. Requires purchase of 2 Not acceptable to BNSF This alternative extends the Not acceptable to BNSF Also, not acceptable to BNSF potentially high environmental SUMMARY NOTES and essentially zero acres for Alternatives 2B and acres of emergent forested wetland (W. of Furnance parcels of private land. Not chosen because of because their high-speed needed industrial tracks south because their high-speed because their high-speed impacts associated with 2C, but involves relocation of Hwy VV. The specific Branch). Involves minor relocation of Hwy VV onto required purchase of Nelson Dewey State Park main line will be blocked into Cassville instead of north main line will be blocked main line will be blocked Mississippi River crossing. In wetland impact and the amount of stone fence private land north of NDSP, with no impact on the property and the subsequent impact on the park while moving unit trains to into wetlands. Impacts less while moving rail cars to and while moving rail cars to and addition, this alternative Acceptable to BNSF. Provides safe impacted depends on final track alignment, and the historic stone fence. Requires purchase of 2 parcels Zero acres of wetland impact. Involves minor property and the historic stone wall. Also not and from the on-site ladder wetlands than Project Design from the on-site unloading Wetland impact reduced from from the unloading facilities, pesents hugh operational access (service road) for operation, maximum stated impacts can not both occur of private land. No projected costs for wetland relocation of Hwy VV onto private land north of chosen because of the length of CTH VV relocation tracks, causing unacceptable but has significant community facilities, causing Project Design, but causing unacceptable challenges since the coal inspections, and maintenance (mutually exclusive). See Alternatives 2A, 2B & 2C mitigation included. Not chosen because of wetland NDSP, with no impact on the historic stone fence. required and the associated costs and impact on operational and safety impact (blocked crossing and unacceptable operational and signifacantly higher estimated operational and safety unloading facility would not be activities. for details. impacts. Requires purchase of 2 parcels of private land. access for users of this road. constraints. noise). safety constraints. costs for bridge construction. constraints. located at NED site.

Page 1 of 2 Revised 10/23/07 Exhibit ___ (RDB-1) Schedule 3

Attachment PSC 2-31(1) Docket No. 6680-CE-170 Wisconsin Power and Light Company

Practicable Rail Delivery Alternative Analysis

Alternatives Determined Not To Be Practicable Analysis Alternative No. 9 Alternative No. 10 Alternative No. 11 Alternative No. 12 Alternative No. 13 Alternative No. 14 Alternative No. 15 Alternative No. 16 Alternative No. 16a Alternative No. 17 Alternative No. 18 Alternative No. 19 Factor Same as Alternative #1 Same as Alternate #1 (Initial Same as Alternate #1 (Initial Same as Alternate #1 (Initial Same as Alternate #1 (Initial Same as Alternate #1 (Initial Same as Alternate #1 (Initial Build two new main line Same as Alternate #16, Same as Alternate #16, Relocate Route VV landside Same as Alternate # 18, (Initial Project Design), Project Design), except Project Design), except Project Design), except Project Design), except Project Design), except Project Design), except tracks between the existing except relocate Hwy VV except relocate Hwy VV to provide enough space to except eliminate service except eliminate the service build only one parallel build only one parallel construct sheet construct sheet construct sheet construct sheet tracks and Hwy VV and use landside to provide enough landside to provide enough build one new main line road. road. industrial track instead of industrial track a minimum pile/retaining wall on pile/retaining wall on pile/retaining wall on pile/retaining wall on the existing main line tracks room for the two new main room for the two new main track and a service road two. of two times the unit train riverside of fill. riverside of fill and riverside of fill and build riverside of fill, build only for the NED industrial line tracks and a service line tracks and eliminate the east of the existing tracks. length with the coal eliminate the service road. only one parallel industrial one parallel industrial track tracks. Service road road. service road. The existing riverside main unloading facilities in the track instead of two. instead of two, and included. line track would be center of the new track Service road included. eliminate the service road. converted to an industrial length. track for NED.

NO - Does not provide NO - Does not provide sufficient safe working sufficient safe working BNSF Design, clearances between tracks. clearances between tracks. Operational, and NO - Insufficient room for Constrains capability to Constrains capability to Safety required safe track spacing. deliver unit trains to NED. Re- deliver unit trains to NED. Re- Acceptability In addition, re-alignment of PENDING - Due to re- PENDING - Due to re- alignment of high speed main alignment of high speed main NO - Constrains capability to NO - Constrains capability to NO - Constrains capability to NO - Constrains capability to high speed main line tracks alignment of high speed main alignment of high speed main line tracks will require BNSF line tracks will require BNSF YES deliver unit trains to NED deliver unit trains to NED YES YES deliver unit trains to NED deliver unit trains to NED would require BNSF approval. line tracks line tracks approval. approval. Use BNSF property for new Use BNSF property for new Use BNSF property for new Use BNSF property for new tracks. Nelson Dewey State tracks. Nelson Dewey State tracks. Nelson Dewey State tracks. Nelson Dewey State Off-Site Land Park and private land req'd Park and private land req'd Park and private land req'd Park and private land req'd for Requirements for relocation of Hwy VV. for relocation of Hwy VV. for relocation of Hwy VV. relocation of Hwy VV. Use BNSF property Use BNSF property Use BNSF property Use BNSF property Use BNSF property Use BNSF property Use BNSF property Use BNSF property Section 4(f) or 6(f) applicable Section 4(f) or 6(f) applicable Section 4(f) and 6(f) Section 4(f) or 6(f) applicable Off-Site Grade Crossing Impacts 1 - Stonefield Village 1 - Stonefield Village 1 - Stonefield Village 1 - Stonefield Village 1 - Stonefield Village 1 - Stonefield Village 1 - Stonefield Village 1 - Stonefield Village 1 - Stonefield Village 1 - Stonefield Village 1 - Stonefield Village 1 - Stonefield Village

Approximately 1.0 acres of Approximately 1.0 acres of Approximately 1.0 acres of Approximately 1.0 acres of Approximately 1.0 acres of Approximately 1.0 acres of Approximately 1.0 acres of mixed emergent and forested mixed emergent and forested mixed emergent and forested mixed emergent and forested mixed emergent and forested mixed emergent and forested mixed emergent and forested wetland west of Furnace Wetland Impacts wetland west of Furnace wetland west of Furnace wetland west of Furnace wetland west of Furnace wetland west of Furnace wetland west of Furnace Branch and 5.2 acres of Branch and 3 acres of Branch and 10 acres of Branch and 6.8 acres of Branch and 3.3 acres of Branch and 3 acres of Branch and 1 acre of forested Approximately 1.0 acres of Approximately 1.0 acres of Approximately 1.0 acres of Approximately 1.0 acres of Approximately 1.0 acres of forested wetlands within the forested wetlands within the forested wetlands within the forested wetlands within the forested wetlands within the forested wetlands within the wetlands within the mixed emergent and forested mixed emergent and forested mixed emergent and forested mixed emergent and forested mixed emergent and forested Mississippi River floodplain Mississippi River floodplain Mississippi River floodplain Mississippi River floodplain Mississippi River floodplain Mississippi River floodplain Mississippi River floodplain wetland west of Furnace wetland west of Furnace wetland west of Furnace wetland west of Furnace wetland west of Furnace north of Stonefield Village. north of Stonefield Village. north of Stonefield Village. north of Stonefield Village. north of Stonefield Village. north of Stonefield Village. north of Stonefield Village. Branch Branch Branch Branch Branch Operational YES - Reduced unit train YES - Coal unloading facility YES - Reduced unit train YES - Reduced unit train YES - Reduced unit train YES - Reduced unit train NONE Impacts to NED delivery capability. would not be on NED site. NONE NONE delivery capability. delivery capability. NONE NONE NONE delivery capability. delivery capability. Air Impacts Base Case Base Case Base Case Base Case Base Case Base Case Base Case Base Case Base Case Base Case Base Case Base Case unnamed creek crossing (1.5 unnamed creek crossing (1.5 unnamed creek crossing (1.5 unnamed creek crossing (1.5 unnamed creek crossing (1.5 Waterway Impacts Dewey Creek crossing Dewey Creek crossing Dewey Creek crossing Dewey Creek crossing Dewey Creek crossing Dewey Creek crossing Dewey Creek crossing miles north of Dewey Creek) miles north of Dewey Creek) miles north of Dewey Creek) miles north of Dewey Creek) miles north of Dewey Creek) Currently under WDNR and Currently under WDNR and Currently under WDNR and Currently under WDNR and Currently under WDNR and Currently under WDNR and Currently under WDNR and Currently under WDNR and Currently under WDNR and Currently under WDNR and Currently under WDNR and Currently under WDNR and the USFWS review. WPL is Threatened & the USFWS review. WPL is the USFWS review. WPL is the USFWS review. WPL is the USFWS review. WPL is the USFWS review. WPL is the USFWS review. WPL is the USFWS review. WPL is the USFWS review. WPL is the USFWS review. WPL is the USFWS review. WPL is the USFWS review. WPL is currently preparing a Endangered currently preparing a currently preparing a currently preparing a currently preparing a currently preparing a currently preparing a currently preparing a currently preparing a currently preparing a currently preparing a currently preparing a Biological Assessment and Species Impacts Biological Assessment and Biological Assessment and Biological Assessment and Biological Assessment and Biological Assessment and Biological Assessment and Biological Assessment and Biological Assessment and Biological Assessment and Biological Assessment and Biological Assessment and Endangered Resource Plan Endangered Resource Plan Endangered Resource Plan Endangered Resource Plan Endangered Resource Plan Endangered Resource Plan Endangered Resource Plan Endangered Resource Plan Endangered Resource Plan Endangered Resource Plan Endangered Resource Plan Endangered Resource Plan for agency review. for agency review. for agency review. for agency review. for agency review. for agency review. for agency review. for agency review. for agency review. for agency review. for agency review. for agency review. Other Environmental & YES - Portion(s) of the YES - Portion(s) of the YES - Portion(s) of the YES - Portion(s) of the Cultural Resource historic stone fence parallel to historic stone fence parallel to historic stone fence parallel to historic stone fence parallel to NONE Impact NONE NONE NONE NONE NONE NONE NONE Hwy VV in NDSP Hwy VV in NDSP Hwy VV in NDSP Hwy VV in NDSP

Cassville Village Impacts

NONE NONE NONE NONE NONE NONE NONE NONE NONE NONE NONE NONE Estimated Construction Cost (Does not include wetland mitigation $10,100,000 costs) $7,800,000 $27,200,000 $14,300,000 $13,100,000 $11,000,000 $9,800,000 $15,300,000 $31,200,000 $21,200,000 $16,600,000 $11,200,000

Elimination of service road Elimination of service road provides unacceptable provides unacceptable conditions for safe switching Not acceptable to BNSF due conditions for safe switching operations, rail car to lack of safe spacing operations, rail car Wetland impact reduced from Wetland impact reduced from Wetland impact reduced from inspections, and track between main line tracks and inspections, and track Project Design, but SUMMARY NOTES Project Design, but Project Design, but Survey measurements show maintenance. Involves industrial track and contraint maintenance. Not acceptable elimination of service road Not acceptable to BNSF due Has greater wetland impacts elimination of service road Not acceptable to BNSF due elimination of service road insufficient space between Involves relocation of Hwy VV relocation of Hwy VV into of having room for only one to BNSF due to lack of safe provides unacceptable to the constraint of having than Project Design. provides unacceptable to the constraint of having provides unacceptable existing main line tracks and into NDSP with significant NDSP with impacts on train at a time at NED (only spacing between main line conditions for safe switching room for only one train at a Opertional challenges since conditions for safe switching room for only one train at a conditions for safe switching Hwy VV for this alternate. impact on portions of the portions of the historic stone one industrial track instead of tracks and industrial track. operations, rail car time at NED. (Because of the coal unloading facility operations, rail car time at NED. (Because of operations, rail car Subject to BNSF approval for historic stone fence. Subject fence. Subject to BNSF two). Subject to BNSF Subject to BNSF approval for inspections, and track only one industrial track would not be located at NED Wetland impact reduced inspections, and track only one industrial track inspections, and track re-alignment of main line to BNSF approval for re- approval for re-alignment of approval for re-alignment of re-alignment of main line maintenance. instead of two) site. slightly from Project Design. maintenance. instead of two) maintenance. tracks. alignment of main line tracks. main line tracks. main line tracks. tracks.

Page 2 of 2 Revised 10/23/07 Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-31(2) Docket No. 6680-CE-170 Wisconsin Power and Light Company Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-31(2) Docket No. 6680-CE-170 Wisconsin Power and Light Company Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-31(2) Docket No. 6680-CE-170 Wisconsin Power and Light Company Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-31(2) Docket No. 6680-CE-170 Wisconsin Power and Light Company

15' 15' MINIMUM Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-32

Data Request No. 2-32:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.18 Waterway and Wetlands

(ref. 1-165 (1.2.18.2.5.2, pp. 231 ff)): The response indicates that the letter provided that is signed by both WP&L and BNSF demonstrates the railroad’s acceptance of this design. The letter only states that the companies will continue to work something out if they can. The letter that follows, to Mr. Cullen of the PSC staff, states that BNSF has agreed to a main line relocation subject to agreement on financial terms and conditions, but it is only a letter from WP&L and not documentation from BNSF. Provide documentation that either of the “Alternative 2” alternatives (A, B, or C) is acceptable to BNSF.

Response:

Please see Attachment 2-32.

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-32 Docket No. 6680-CE-170 Page 1 of 2 Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-32 Docket No. 6680-CE-170 Page 2 of 2 Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-33

Data Request No. 2-33:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.18 Waterway and Wetlands

(ref. 1-166 (1.2.18.2.5.2)): The response did not provide the requested documentation that the acquisition of up to 1 acre of Nelson Dewey State Park land is acceptable to DNR. Provide this documentation, particularly for Alternative 2C in the matrix table for this section, as clarified in the response to item 1-73.

Response:

Alternative 2C is not the proposed practicable alternative. WPL has committed to eliminating all wetland impacts north of NED for the railroad relocation project through redesigning Alternative 2B. WPL’s preferred Alternative 2B does not require acquisition of any Nelson Dewey State Park land. See Response to Data Request No. 2-31. WPL has discussed purchasing Nelson Dewey State Park land for Alternative 2C with the DNR. Alternative 2C requires cooperation of the Wisconsin Historical Society (WHS) due to impacts to the stone fence, and the WHS is beginning its review of potential stone fence impacts. If Alternative 2B is for some reason not acceptable to the DNR during the permitting process, the DNR has agreed to cooperate with WPL and WHS in connection with Alternative 2C. WHS has also agreed to cooperate with WPL under its established protocols. Neither the DNR nor the WHS can commit in writing to Alternative 2C at this time, however, because the Chapter 30 permit application review process and the WHS review of impacts to the stone fence have not been completed.

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-34

Docket Number: 6680-CE-170 Date of Request: September 13, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Wisconsin Power and Light Company Author’s Telephone No.: 608-458-3951 Witness: (If other than Author)

Data Request No. 2-34:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.18 Waterway and Wetlands

(ref. 1-167 (1.2.18.2.5.2)): The response did not provide the requested documentation that the potential impacts of the alternative rail configuration on the stone fence in the Nelson Dewey State Park is acceptable to DNR and the Wisconsin Historical Society, or the documentation of progress toward compliance with Section 106 of the National Historic Preservation Act. Provide this documentation, particularly for Alternative 2C in the table for this section, as clarified in the response to item 1-73.

Response:

See Response to Data Request No. 2-33 and Attachment 2-34.

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-34 Docket No. 6680-CE-170 Page 1 of 1

FW WPL Nelson Dewey Baseload Electric Generation Facility.txt

------From: Pyper, Thomas TMP (7122) Sent: Monday, October 01, 2007 5:15 PM To: Chip Brown Cc: 'Sturgeon, Ritchie'; 'Graber, Ron'; 'Shefchek, Joe' Subject: WPL Nelson Dewey Baseload Electric Generation Facility

Chip: I am following up on our telephone conversation from a few months ago during which we discussed Wisconsin Power and Light Company's (WPL) project to add a third electric generating baseload unit at the Nelson Dewey Generating Station (NED) in Cassville, Wisconsin. We talked in general about the potential impact to a stone fence adjacent to County Highway V V north of NED, which may of historic significance and, thus, fall within the State Historical Society's jurisdiction. You indicated that you would be willing to cooperate with WPL's project but that there is an intra-agency protocol that must be followed to bring you into the project with the on-going project review by the Public Service Commission of Wisconsin (PSC) and the Wisconsin Department of Natural Resources (DNR). I am inquiring to see if that protocol has been implemented or if there is anything I can do on behalf of WPL to supply you with any information you need to become familiar with WPL's plans. At present WPL's project would not result in an impact to the stone fence we discussed, but in the event that plans need to be changed based on the regulatory review, I would like to provide you with any information you need to become familiar with how the project is progressing. Again, I appreciate your willingness to cooperate with the other agencies and WPL (in line with the protocol you mentioned). Please let me know if there is anything I can do to help in your role as a potentially involved agency. Tom Pyper Whyte Hirschboeck Dudek S.C. 33 East Main Street, Suite 300 Madison, Wisconsin 53701 (608) 255-4440 (608) 258-7138 (fax)

Page 1 Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-35

Data Request No. 2-35:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.20 Water Source, Specific

(ref. 1-169 (1.2.20.4.2.3, pp. 248 ff)): The Stormwater Plan submitted with this response indicates that the storm sewer pipe would discharge just downriver from the existing plant. What is the volume of water expected to be discharged at this outfall? What would be the impacts of the sewer discharge on the mussel beds in the Mississippi? Discuss potential impacts to rare mussel or fish species that might occur because of the construction or operation of this outfall.

Response:

The storm water pipe outfall discharge pipe is planned to be located in an area just upstream of the existing WPL boat landing and downstream from the existing barge mooring cells and NED Units 1 and 2 discharge structure. The plan is to locate the pipe so the discharge will occur onto the existing rip rap stabilized bank. The preliminary volume of water that is expected to be intermittently discharged from this outfall location is estimated to average 32 cubic feet per second (cfs). The storm water will be discharged in accordance with permit requirements and, as a result, impacts to the mussel beds are not anticipated. Additionally, since the location of the outfall structure is planned to be located on the rip rap bank, mussels or fish species are not expected to be impacted during the construction or operation of the structure. Mussel surveys (transects COE6 and E2) have previously been performed in the vicinity of the proposed outfall structure (see Ecological Specialists, Inc. Mussel Survey Report, dated January 2007).

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-36

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Kirby Letheby Author’s Title: Team Lead – New Generation Author’s Telephone No.: (608) 458-3276 Witness: (If other than Author)

Data Request No. 2-36:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.20 Water Source, Specific

(ref. 1-170 (1.2.20.2.2)): Describe, map, and diagram the changes in stormwater ponds discussed in the response to this item.

Response:

The existing coal pile runoff pond will be closed and a new pond will be constructed to the southeast of the coal pile area and to the east of the substation. A new coal pile runoff pond to collect the runoff from the increased coal yard size will be constructed on the northwest end of the new coal yard area. A stormwater pond for the new plant area development will be constructed on the river side of the new power block area. These ponds are labeled on the Plant and Facilities Plan (Attachment PSC 2-36) as item #22 “coal pile runoff ponds” located both southeast and northwest of the coal yard area, and #32 “stormwater detention pond.”

Page 1 of 1

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-36

KEY INDEX

37 1 TURBINE GENERATOR

2 BOILER

3 DRY POLISHING SCRUBBER 27 4 BAG HOUSE 26 5 STACK

6 FLY ASH SILO

7 COOLING TOWER

8 CAR DUMPER

9 PROPERTY LINE

10 COAL CONVEYOR

11 150 DAY COAL/PET COKE PILE

28 12 NEW BARGE UNLOADER

13 CRUSHER HOUSE

14 WATER TREATMENT

15 LIMESTONE UNLOADING

16 COVERED LIMESTONE STORAGE

17 TEMPORARY PLANT ACCESS ROAD 9 18 CONSTRUCTION PARKING

19 CONSTRUCTION OFFICE TRAILERS

20 BIOMASS HANDLING AREA

21 LIME SILO

22 COAL PILE RUNOFF POND

23 FUEL OIL STORAGE TANK

24 SORBENT INJECTION STORAGE SILO

25 SERVICE WATER TANK 22 8 26 LOADED UNIT TRAIN PARALLEL INDUSTRIAL TRACK

27 UNLOADED UNIT TRAIN PARALLEL INDUSTRIAL TRACK

28 TRACK SERVICE ROAD

17 30 29 DEMINERALIZED WATER TANK

30 COAL/PET COKE STACKOUT/RECLAIM 36 31 COLLECTOR WELL

32 STORMWATER DETENTION POND

41 LIMESTONE PREPARATION BUILDING 38 12 6 42 POTENTIAL OFF-SITE CONSTRUCTION PARKING 35 34 15 43 POTENTIAL OFF-SITE LAYDOWN

33 41 40 19

2 25 1 42 29

5 3 31 4 14 39 32 7 SOURCE: AERIAL PHOTO - NAIP 2005 AERIAL IMAGERY 21 43

NORTH 24

MISSISSIPPI RIVER

500' 0' 500'

Plant and Facilities Plan SCALE IN FEET NED 3 Preferred Site Wisconsin Power and Light Company

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-37

Data Request No. 2-37:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.32 Publicly Owned Lands

(ref. 1-177 (1.2.32) and 1-108 (1.2.1.2, pp. 278-279)): Item b. requests clarification about whether or how any of the other facilities associated with the project affect Refuge properties. The response does not discuss the associated transmission lines. The response to 1-108 addresses transmission lines but is a brief list. Describe how transmission line construction (for each of the items listed in the response to 1-108) would take place in the Refuge.

Response:

It is expected that the transmission line construction activities will be controlled by the specific requirements of each landowner, including the US Fish and Wildlife Service, which controls much of the land within the Refuge. Minimal construction impact is anticipated on the government owned land since the route across government land will reuse an existing transmission line corridor through this area.

Material staging areas and construction access will need to be arranged with the property owners. Gravel, rock and mats may be used as necessary to firm up staging areas, right-of-way and access to right-of-way for supporting utility vehicles (trucks, trailers) during the construction process.

Removal of existing poles and setting of new poles requires that utility trucks and trailers have access to the pole locations. Structure assembly and wire stringing are also done from utility bucket trucks.

Tree trimming and clearing is anticipated in areas where trees would interfere with the construction and operation of the line. Page 1 of 2

Exhibit ___ (RDB-1) Schedule 3

For any sensitive areas or restricted access areas, the use of helicopters for activities such as hauling materials, setting poles and tree trimming is possible to reduce impact on the land. For areas where the ground is not firm, construction during winter months when the ground is frozen can be done to reduce impact on the land.

Land restoration activities include; removal of rock, gravel and mats, tilling of the ground, adding top soil and seeding as necessary.

Page 2 of 2

Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request No. 2-38

Docket Number: 6680-CE-170 Date of Request: June 4, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Kirby Letheby Author’s Title: Team Lead – Wisconsin Baseload Author’s Telephone No.: (608)458-3276 Witness: (If other than Author)

Data Request No. 2-38:

1.2 Natural and Community Resources, Description and Potential Impacts

1.2.34 Local Government Impacts

(ref. 1-182 (1.2.34, p. 282)): The responses to this item discuss the mainline trains and the operation of the coal delivery trains. It does not discuss the impacts during construction of the new industrial rail facilities. For example, how will visitors or staff be able to reach Stonefield Village during construction of the new rail line? Would dust or noise interfere with Stonefield educational work? Would there be a need to close the facility at any time during construction?

Response:

Since most of the track construction will not be close to Stonefield Village, the track construction impacts on the pedestrian and vehicular access to Stonefield Village will be limited to only the construction activities that will occur at the existing railroad crossing at the entrance to the facility. The proposed modifications at the Stonefield Village entrance include the relocation of the existing two BNSF main line tracks and the construction of one new parallel industrial track. See the attached drawing, titled “Stonefield Village Track Crossing” (Attachment PSC 2-38), for a view of the proposed track modifications at this specific location.

During the active construction at the entrance to Stonefield Village and for several hundred feet on either side of the crossing, pedestrian and vehicular access will need to be blocked. The construction, however, will be done in several steps. For each step only a small portion of the total track related work will occur in front of Stonefield Village. Therefore, there will be time (days or weeks) between these steps in construction activities when temporary pedestrian and vehicular access to Stonefield Village will be available. Page 1 of 2

Exhibit ___ (RDB-1) Schedule 3

Examples of track construction activities that are expected to temporarily block access to Stonefield Village are:

1. Site preparation and grading 2. Placement and compacting of sub-ballast 3. Placement of new rails & ties on sub-ballast 4. Placement & tamping of ballast 5. Removal of abandoned main line rails & ties 6. Restoration of road surface through the crossing

While a detailed construction schedule is not yet available, the duration that the above activities will block access is expected to be measured in hours or days, rather than weeks or months. Also, with the exception of items 3 and 4 listed above, there will be flexibility in the scheduling of construction steps in order to minimize impacting the access to Stonefield Village during peak activity periods. Items 3 and 4 will involve the use of specialized equipment that has very limited availability, and, as a result, there will be little schedule flexibility for these two activities.

While track construction activities for areas other than the Stonefield Village entrance will not block access to the site, these activities will result in a general increase of heavy truck traffic on Highway VV. To help mitigate this situation, the appropriate use and placement of construction warning signs and flagman will be used to warn and control vehicular and pedestrian traffic when needed.

Page 2 of 2

Exhibit ___ (RDB-1) Schedule 3 Attachment PSC 2-38

PARKING LOT

NEW RELOCATED BNSF TRACK

NEW PARALLEL INDUSTRIAL TRACK FOR NELSON DEWEY

EXISTING BNSF TRACK EXISTING BNSF TRACK CROSSING

STONEFIELD VILLAGE PARKING AREA

NEW PARALLEL END OF NEW INDUSTRIAL TRACK RELCOATED FOR NELSON DEWEY BNSF TRACK

NORTH

END OF NEW 50' 0' 50' RELCOATED Stonefield Village Track Crossing BNSF TRACK SCALE IN FEET NED 3 Preferred Site Wisconsin Power and Light Company Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin September 13, 2007 Data Request – Barge Unloader

Docket Number: 6680-CE-170 Date of Request: September 13, 2007 Information Requested By: Christine Swailes Date Responded: Author: Kirby Letheby Author’s Title: Team Lead – New Generation Author’s Telephone No.: (608) 458-3276 Witness: (If other than Author)

SEPTEMBER 13, 2007 DATA REQUEST – BARGE UNLOADER:

1. Identify the next steps that must be followed by WPL, FWS and DNR in reviewing the potential impacts on the rare mussels and fish, including the Biological Assessment requirements for the FWS, along with the subsequent review steps for both the FWS and DNR. Provide an estimate of the timeline for each of the necessary agency review steps.

RESPONSE:

On August 31, 2007 WPL submitted its most recent mussel survey and fish habitat report to the DNR and FWS. Neither DNR nor the FWS has formally responded to WPL concerning its review of this report. WPL is also in the process of completing a barge traffic study, which is currently anticipated to be completed in October. Once the barge traffic study is completed, WPL will compile all relevant information gathered to date from its own surveys and from information provided by FWS and DNR to evaluate potential impacts from NED 3 upon state and/or federally-listed species. After WPL completes its evaluation, it will issue two reports – a biological assessment (“BA”), to address federally-listed species, and an Endangered Resource Plan Report (“ERP Report”), to address state-listed species. WPL is projecting to issue the BA and ERP Report on November 1, 2007, which should be sufficient for developing and issuing a Final Joint Federal/State Environmental Impact Statement (“Joint EIS”) by May 1, 2008.

WPL is also in the process of updating its Wis. Stat. § 30.025 permit application. WPL anticipates submitting its updated permit application to both the U. S. Army Corps of Engineers (“USACE”) and DNR toward the end of October, 2007. Generally, submittal of a permit application to USACE initiates consultation

Page 1 of 9 Exhibit ___ (RDB-1) Schedule 3

between USACE and FWS pursuant to Section 7 of the Endangered Species Act. With respect to NED 3, it is anticipated that the formal Section 7 consultation process will be followed. Many activities required to complete the formal Section 7 consultation process have already been completed, e.g. obtaining information from FWS concerning the potential presence of Federally- listed species and on-site species surveys. Thus, at this point, formal consultation between USACE and FWS will involve USACE/FWS evaluation of the BA. Formal consultation generally terminates with the FWS’ issuance of a Biological Opinion (“BO”) that outlines whether a project will jeopardize the continued existence of a Federally-listed species or result in destruction or adverse modification of critical habitat. Generally, a Biological Opinion also forms the basis for a Section 7 ESA incidental take authorization. Although Federal regulations set forth timelines applicable to the formal Section 7 consultation process, the actual timelines that will be followed to complete the NED 3 formal Section 7 consultation process will be addressed through a Memorandum of Understanding between the PSC, USACE, DNR and WPL, as discussed below.

In contrast to the Federal Section 7 consultation process, Wisconsin statutes and regulations do not outline specific procedural milestones with corresponding timelines for completing Wis. Stat. § 29.604(6r) interagency consultation. According to DNR, the flowchart located at http://www.dnr.state.wi.us/org/land/er/take/, outlines the state’s incidental take authorization process. WPL understands that further discussions with DNR will be necessary to outline the precise steps and timelines associated therewith that will be necessary to complete the Wis. Stat. § 29.604(6r) process.

WPL sent USACE a September 17, 2007 letter requesting that the USACE initiate the process of developing a Memorandum of Understanding between USACE, PSC, DNR and WPL to develop a Joint Federal/State Environmental Impact Statement to satisfy both the Federal National Environmental Policy Act and Wisconsin Environmental Policy Act. WPL specifically requested in its letter to USACE that the MOU include within it a schedule of key deadlines by which consultation with other agencies would be completed, e.g. FWS and DNR Bureau of Endangered Resources. Thus, WPL anticipates that the timeline for each agency to complete its endangered species evaluations and interagency consultation obligations will be addressed within the forthcoming MOU. Although the specific timeline to accomplish both the Federal and state endangered species consultation requirements is not known at this time, WPL anticipates that both Federal and state endangered species review will be satisfied to permit issuance of the Final Joint EIS by May 1, 2008, which will provide sufficient time for the PSC to issue its decision on WPL’s CPCN Application within the statutory timeline.

1. Given the presence of rare species at the revised unloader site, provide additional information on the option of rebuilding the existing unloader to increase its unloading

Page 2 of 9 Exhibit ___ (RDB-1) Schedule 3

capacity. Provide information on what equipment and structures would be needed, the specific steps that would be taken to construct an expanded unloader, and the associated type and extent of disturbance to the bed of the river for each step of the construction process.

In addition, provide a cost estimate, along with an evaluation of any potential limitations or constraints an expanded unloader would have, compared to a new additional unloader.

RESPONSE:

Rebuilding the existing barge unloader was one of the barge unloading options evaluated when making the decision to increase barge unloading capacity. The information requested on rebuilding the existing barge unloader is provided below in response to question 4.

Cost estimates were established to determine the relative difference between the option to “Rebuild Existing Barge Unloader (OPTION)” designated as option 1 and the option to add a “New Barge Unloader” designated as option 2. The initial cost estimates for option 1 to rebuild the existing barge unloader had assumed that a portion of the existing unloader foundation and structure might be used. This resulted in a cost difference of about 10% more cost for option 2 to build a new barge unloader. When a feasibility study was completed on these two options, the following table was prepared to distinguish the attributes of each:

ATTRIBUTE Option 1 – Rebuild Existing Option 2 – Add Second Unloader Unloader Barge Unloading Time Increases unloading capacity, Potentially faster unloading and Cycle using single unloader. cycle given two unloaders operating in parallel. Redundancy Single redundancy, which Redundant unloaders, could produce problems although existing unloader is during unloader or discharge of lower capacity. conveyor forced outage. Unit Interconnection Interconnection of existing Can simply feed to either the Unit 1&2 feed and Unit 3 feed existing Unit 1 & 2 Crusher occurs at new transfer tower Building and new Unit 3 (alternate is via reclaim). Crusher Building. Constructability Construction is limited to Construction can take place winter season only, to avoid year round. Unit 1&2 outage which increases cost (unless deferred until after rail is available).

Page 3 of 9 Exhibit ___ (RDB-1) Schedule 3

ATTRIBUTE Option 1 – Rebuild Existing Option 2 – Add Second Unloader Unloader

Capital Cost (see Slightly lower capital cost Slightly higher capital cost Below) than Option 2, within 10%. (about 10% or $600k) over Option 1, and slightly higher O&M costs due to two unloaders.

Environmental Impacts Minimal impacts on River. Impact of new cells and Impact of rebuild construction unloader foundation on on aquatic life including aquatic life including mussels mussels viewed to be minimal viewed to be minimal and and non-invasive after mussel non-invasive after mussel relocation. relocation. Operator Interface Same operating staff as Multiple unloading operations current system. in parallel has potential to increase operating staff. Barge Handling and Modification to the existing More complicated barge Positioning (Cable barge handling cable system. handling cable system System) required to handle two barges simultaneously or separately In-River Construction Increased traffic on the Additional mooring cells and and Traffic current river traffic footprint, dock extension will be due to third unit. required. Slightly modified traffic pattern for tug and barges in front of station.

Based on greater redundancy, decreased cycle time, impact levels and cost, Option 2 was selected as the best available barge unloader option for implementation even though such was viewed to have a slightly higher capital cost. The forecasted cost for rebuilding the existing unloader (Option 1) is $5.9 Million. The forecasted cost for adding the second unloader (Option 2) is $6.6 Million.

2. Provide information to clarify the capacity of the existing unloader system to unload additional coal/coke volumes at NED. Provide an analysis of how much additional coal/coke could be unloaded and describe the operational changes that would be needed for these additional volumes.

RESPONSE:

The existing barge unloader, mooring cells, and dock walkway were all constructed with the original Nelson Dewey Generating Station in 1959, with some improvements made over the years and major unloader reinforcements

Page 4 of 9 Exhibit ___ (RDB-1) Schedule 3

and spill skirts installed in calendar year 2006. At maximum capacity of roughly 600 tons per hour, this unloader is considered to be already at its limit for serving Units 1 and 2 only and well undersized for handling the existing units and the addition of Unit 3 needs.

3. Include modifications to the barge unloader design in the revisions to the DNR Chapter 30 permit application, which was discussed previously under the “Chapter 30 Permit Revisions” item.

RESPONSE:

Information on modifications to the existing barge unloader will be added to the Chapter 30 permit application. This information will be included as an option, “Optional Barge Unloader Design Configuration NED 3 Preferred Site,” to the current plan of adding a new barge unloader.

Below is a draft text that provides the requested scope and content information.

OPTIONAL BARGE UNLOADER DESIGN CONFIGURATION NED 3 PREFERRED SITE

Background Receipt of 100-percent of coal and pet coke for proposed NED Units 1, 2, and 3 via river barge requires either replacement of the existing mechanical clam shell bucket unloader (Option) or addition of a second unloader (Preferred Site). It was determined that a continuous bucket elevator (CBE) unloader was the best technology choice for either option, with design unloading capacity dependent on the option selected. Each option requires some construction in the river adjacent to the existing unloader and said construction is the focus of this appendix.

The existing unloader, mooring cells, and dock walkway were all constructed with the original Nelson Dewey Generating Station in 1959, with some improvements made over the years and major unloader reinforcements and spill skirts installed in calendar year 2006. At maximum capacity of roughly 600 tons per hour, this unloader is considered to be already at its limit for serving Units 1 and 2 only and well undersized for handling the existing units and Unit 3 needs.

Unloader Configuration This appendix and technical content is based on selection of the replacement Option for implementation. Bathymetric data taken in calendar year 2006 is the basis for the amount of dredging quantified herein. As indicated in the Application, the proposed capacity for a single unloader is 3,000 tons peak per hour (2,000 average) using a cantilevered continuous bucket elevator (CBE). Benefits from this technology selection and placement include limited amount of

Page 5 of 9 Exhibit ___ (RDB-1) Schedule 3

in-river construction, reduced damage to the barges during unloading, and faster unloading time per barge. However, the configuration and loads generated by this unloader require complete replacement of the unloader superstructure, portions of the unloader foundation, and virtually all auxiliaries (hopper, feed conveyor, others).

The following technical input is based on historical data and the conceptual unloader design noted and is subject to change in detail design. Based on review of the existing unloader from original drawings, there are two possible alternatives for replacement under this Option:

1. Demolish the existing unloader superstructure, transfer hopper, and existing discharge conveyor C-1, and replace in-kind with new CBE unloader and conveyors; or,

2. Construct new barge unloader in adjacent dock bay, demolish the existing unloader, hopper, and discharge conveyor C-1, rework the dock and barge positioning system, and install new hoppers and conveyors.

Each of these alternatives has advantages and disadvantages, and there is no clear-cut selection possible. This appendix is based on alternative #1 above, principally selected because it takes advantage of the existing cofferdam in the river bed and maintains the unloader in the centroid of the dock and existing barge positioning system. Regardless of alternative, demolition of the existing unloader superstructure, transfer hopper, and conveyor C-1 will need to take place immediately following receipt of the last barge of the shipping season (November, in calendar year 2008 or 2009) to ensure that the replacement unloader is functional prior to the start of the next shipping season. There is some risk that, due to winter conditions and receipt of new unloader and auxiliaries, the new unloader will not be complete the following spring.

After the unloader superstructure is removed, it will be necessary to either demolish the existing unloader foundation cap or to cut holes in such to accommodate new driven piles. As this slab varies in thickness from 2’ to 4’-6” thick, replacement will probably be necessary, although it may be possible to save portions for use as a work platform. The existing cellular cofferdam (sheet pile) will be left in-place and new driven piles will be driven inside and outside of the cofferdam to support the new unloader foundation. Preliminary vendor information indicates that the new unloader foundation will be of approximate dimensions of 50 feet by 45 feet, subject to final design. Some minor local dredging and soil removal may be needed to facilitate unloader foundation construction. After foundation pour and cure, the new unloader and appurtenances will require installation, and all hoppers and conveyors will be installed to support the new on-site material handling system.

Page 6 of 9 Exhibit ___ (RDB-1) Schedule 3

Primary new construction adjacent to or in the River includes the installation of new driven piles in the river and in the bank and unloader foundation (mounted on the river bank) form construction and pouring, which will require use of in-river construction techniques. Existing rip-rap along the river bank will be retained where possible; the only significant impacts will be adjacent to the existing unloader foundation. The balance of the work will be managed from the river bank via temporary staging for personnel safety and security reasons.

The elevated barge unloader foundation will be approximately 50 feet wide by 45 feet long, and will extend into the river approximately 55 feet to align with the outer cell (barge) line, consistent with the existing unloader. The foundation will consist of driven steel H-piles or concrete piles or piers, installed by both a pile driving rig with extended boom located on the bank and barge-mounted pile driving rig (outer piles/piers). Reinforced concrete pile caps and unloader mat foundation will require installation from both a temporary barge and the river bank (with all concrete pumped into foundation formwork from the river bank). The unloader superstructure will then be built on top of this pile-supported foundation from land access. Use of driven piles will minimize how much dredging is required for the unloader foundation and to provide structural support for significant live loads produced by the unloader when in-service. Final design will confirm construction methods required; the foundation construction may be aided by installation of permanent sheeting piling on one or more sides of the new unloader foundation.

The existing dock walkway will be re-installed from the two adjacent mooring cells. No new protrusions into the river will be required and the existing dock length can be preserved. The top of the dock structure is completely above the normal pool waterline and ordinary high water mark.

Technical Content The following technical data is based on conceptual data developed to-date for replacing the existing barge unloader (Option).

Affected River Area The River bottom “work area” that will be affected by demolition of the existing unloader and construction of the new CBE unloader is approximately 120 feet by 100 feet (0.3 acres).

Construction Prerequisites 1. Relocation of freshwater mussels within the work area, if any (as defined by perimeter of sediment curtain and if mandated by Chapter 30 or other permitting); 2. Installation of a temporary sediment curtain in the River surrounding the work area will prevent re-suspension of solids and transport downstream during local dredging and foundation work. This sediment curtain will also

Page 7 of 9 Exhibit ___ (RDB-1) Schedule 3

serve the dual purpose of keeping fish and other aquatic wildlife out of the construction zone and potential harm. 3. Staking of all new construction by assigned coordinates. 4. Isolation of all existing unloader and discharge conveyor C-1 equipment from existing power supplies.

No temporary structures will be required to construct the new unloader foundation and superstructures. All staging areas will be on land adjacent to the work area.

Sediment Curtain During construction, a floating silt (or turbidity) curtain constructed of reinforced polyethylene (RPE) foam top and bottom, elastomeric or polymeric coated geotextile fabric curtain body (vulcanized seams), and appropriate connecting chains and galvanized cable, aluminum connection hardware and anchors will be used to retain sediment created by construction within the curtain and fish and other aquatic life out of the construction area. The top curtain will be equipped with floating expanded polystyrene float material of safety yellow color and navigation markers. The bottom of the curtain will be weighted down and slightly embedded in the river bed.

The curtain will remain in place for the duration of construction; following construction, any accumulated debris at the river bottom and surface will be removed before curtain removal. To ensure that wave and wind action do not damage the curtain, intermediary posts will also be embedded in the river bottom at periodic intervals for curtain anchorage. The curtain will be manufactured by AmericanMarine, Geomembrane, Layfield, or similar.

The size, weight, and overall number of the anchors shall be sufficient to hold the sediment curtain in its defined location and will be confirmed in final design. Alternate anchoring methods, such as heavy concrete weights or driven pilings, may be developed during final design. Given that the construction zone is outside the flow path of the main shipping channel and Cassville Slough, the normal river current is not expected to be strong.

Dredging Based on 2006 bathymetric data, primary dredging associated with this new unloader and mooring cell construction process is associated with the build-up of sediment on the river side at the shoreline. Removal of this material and existing rip rap at shoreline will promote improved access to the new equipment. There may also be a need for further dredging within the work area to ensure that at least 12-foot depth is provided (sedimentation may have occurred since the bathymetric study in 2006). The total amount of excavated and dredged material is estimated to be less than 200 cubic yards. From prior dredging to the south at the existing unloader in 2006, this material is expected to be primarily sand and silt, with some organics and gravel. This material will be placed in dump trucks

Page 8 of 9 Exhibit ___ (RDB-1) Schedule 3

and relocated to an on-site storage location, after carriage water is allowed to return to the river by gravity.

The amount of dredge material and on-site storage exempts the project from solid waste licensing requirements. On-site storage will generally be in berms, used to reduce any fugitive dust and noise emissions associated with adjacent properties and CTH VV; such placement will also improve stability of said soils and prevent its displacement. Final dredge locations will be defined on site arrangement drawings.

Construction Methods In summary, construction of the replacement unloader will consist of a combination of on-bank and barge-based conventional construction practices, all preceded by the prerequisite demolition and curtain installation activities noted above. Given the location and configuration of the new unloader, dredging will be minimal.

It is currently anticipated that all dredging will be accomplished with an on-bank dragline as such soils are immediately adjacent to the bank. Dredged material will be directly deposited into dump trucks (with carriage water return by gravity) for on-site deposition.

In-river construction will include installation of driven H-piles and possibly sheet pile to simplify needs for stability and structural support and minimize environmental impacts. The in-river footprint will be limited to the unloader foundation placed between two of the existing cells, and this will be above the existing cofferdam. Permanent construction in the river will include a number of driven piles within the footprint of the exiting unloader. The existing river course will remain intact. The only bank modification will be in the vicinity of the unloader foundation, where existing rip-rap will be modified.

Construction work from tug/barge combination or vessel will be limited to piling installation. After driven pile construction, lashed-in-place barges may also be used to access the existing cofferdam for gravel fill placement and improved access. However, current plans call for this effort to be primarily via on-bank crane and clamshell bucket or similar system. The cells will be filled with clean gravel from local sources for improved stability. Barges may also be used to install formwork for the elevated bucket unloader pile cap and mat foundation.

River-bank construction methods will be used for all superstructure construction, and preferentially used over on-barge construction for safety and efficiency reasons. Given the location of the modified unloader foundation in the general plant area and retention of the existing cellular cofferdam to work from, on-bank construction methods are simplified.

Page 9 of 9 Exhibit ___ (RDB-1) Schedule 3

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Sept. 13, 2007 Data Request - Cost

Docket Number: 6680-CE-170 Date of Request: September 13, 2007 Information Requested By: Christine Swailes Date Responded: October 23, 2007 Author: Mel Miranda, Author’s Title: Financial Manager – Wisconsin Baseload Project Randy Bauer Author’s Title: Manager Asset Strategy Author’s Telephone No.: (608) 458-3246, (319) 786-7220 Witness: (If other than Author)

September 13, 2007 Data Request - Cost

a) Provide updated cost estimates for the proposed technologies. This includes updated responses to 1-36 (AFUDC amounts) and 1-49 (capital & operating costs).

b) If rail cars are to be rented, provide an Excel spreadsheet showing how the rental costs are included in O&M expenditures, either fixed or variable, within EGEAS.

c) Provide an Excel spreadsheet indicating how the proportionately shared costs are included within EGEAS.

Response: a) WPL is presently working with a contractor in the development of the engineering design and a corresponding target cost for NED 3. It will take several months to complete such tasks. WPL’s contractor and owner’s engineers have reviewed the existing cost estimate for the impact of major scope changes and market changes for major cost items. At this time, the result of the review points to an approximate cost increase of 5-7% on an escalated basis. This increase applies to the $855 million estimated cost previously provided. This primarily covers increased scope to support the handling and firing of biomass fuels, further rail related work to eliminate impact on wetlands, and market impact on the cost of some major items. The AFUDC amounts (reference response to Data Request No. 1-36) for NED 3 also increase proportionally by the same factor as the overall cost.

As with NED 3, the estimated costs for COL 3 were also reviewed by WPL’s contractor and owner’s engineers. The result of the review was an estimated Page 1 of 2

Exhibit ___ (RDB-1) Schedule 3

cost increase of 8-10% on an escalated basis. This increase applies to the $875 million estimated cost previously provided. It covers primarily increased scope to include a Wet Precipitator, a Zero Discharge De-watering System, and market impact on the cost of some major items. The AFUDC amounts (see Response to Data Request No. 1-36) for COL 3 also increase proportionately by the same factor as the overall cost. b) Rail cars are to be rented at both NED3 and COL3. Response to Data Request No. 1-41 indicated a cost adder of $2.3 million per year in current dollars. This equates to a Fixed O&M adder of $7.67/kW in 2007$, or $7.38 in 2005$.

For the purposes of EGEAS, $7.38 should be added to the Fixed O&M 2005 Base Value for all coal options for like comparison. c) The cost of shared items, totaling $167 million on an escalated basis, are included in the NED 3 cost estimate, except for the cost of the stack amounting to $13 million that is part of the NED 1&2 Certificate of Authority. Therefore, all NED 3 costs related to shared items are already included within EGEAS as part of the NED 3 overall costs.

Page 2 of 2

Exhibit ____ (RDB-1) Schedule 3 CONFIDENTIAL Attachment

Response of Wisconsin Power and Light Company to The Public Service Commission of Wisconsin Data Request KD-03 Verbal

Docket Number: 6680-CE-170 Date of Request: July 2, 2007 Information Requested By: Ken Detmer Date Responded: July 12, 2007 Author: Randy Bauer Author’s Title: Manager – Asset Strategy Author’s Telephone No.: (319) 786-7220 Witness: (If other than Author)

Data Request KD-03 Verbal:

Provide the EGEAS files from the 2006 IRP in support of the CPCN.

Response:

A compact disk containing WPL 2006 IRP EGEAS files has been submitted to the PSC.

Page 1 of 1

Exhibit ____ (RDB-1) Schedule 3 Exhibit ____ (RDB-1) Schedule 3 Exhibit ____ (RDB-1) Schedule 3

BEFORE THE

PUBLIC SERVICE COMMISSION OF WISCONSIN

Application of Wisconsin Power and Light Company d.b.a. Alliant Energy 6680-CE-170 for Authority to Construct a New Coal-fired Electric Generation Unit Known as the Nelson Dewey Generating Station in Cassville, Grant County, Wisconsin

SERVICE LIST (March 13, 2008)

WISCONSIN POWER AND LIGHT COMPANY Thomas M. Pyper Cynthia L. Buchko Whyte Hirschboeck Dudek, S.C. 33 East Main Street, Suite 300 Madison, WI 53703 (Phone: 608-255-4440 / Fax: 608-258-7138) (Email: [email protected]; [email protected])

AMERICAN TRANSMISSION COMPANY Charles Cummings Patrisha Smith N19 W23993 Ridgeview Parkway W Waukesha, WI 53188 (Phone: 262-506-6807 – CC; 262-506-6145 – PS) (Fax: 262-506-6710) (Email: [email protected]; [email protected])

CITIZENS UTILITY BOARD Curt F. Pawlisch Kira E. Loehr Cullen Weston Pines & Bach LLP 122 West Washington Avenue, Suite 900 Madison, WI 53703 (Phone: 608-251-0101 / Fax: 608-251-2883) (Email: [email protected]; [email protected])

Docket 6680-CE-170 Exhibit ____ (RDB-1) Schedule 3

CLEAN WISCONSIN David C. Bender Pamela R. McGillivray Garvey McNeil & McGillivray, S.C. 634 West Main Street, Suite 101 Madison, WI 53703 (Phone: 608-256-1003 / Fax: 608-256-0933) (Email: [email protected]; [email protected])

DAIRYLAND POWER COOPERATIVE Jeffrey L. Landsman Wheeler, Van Sickle & Anderson, S.C. 25 West Main Street, Suite 801 Madison, WI 53703 (Phone: 608-255-7277 / Fax: 608-255-6006) (Email: [email protected])

E4, INC. Kathryn Sachs 431 Charmany Drive, Suite 101 Madison, WI 53719 (Phone: 608-204-0091 / Fax: 608-204-0092) (Email: [email protected])

IBEW LOCAL 965 Mike Pyne 1602 South Park Street, Room 220 Madison, WI 53715-2108 (Phone: 608-259-2400) (Email: [email protected])

RENEW WISCONSIN Michael Vickerman 222 South Hamilton Street Madison, WI 53703 (Phone: 608-255-4044) (Email: [email protected])

WE ENERGIES Paul Farron 231 West Michigan Street Milwaukee, WI 53203 (Phone: 414-221-3958) (Email: [email protected])

Page 2 of 4 Docket 6680-CE-170 Exhibit ____ (RDB-1) Schedule 3

WISCONSIN INDUSTRIAL ENERGY GROUP Steven A. Heinzen LaFollette Godfrey & Kahn PO Box 2719 Madison, WI 53701-2719 (Phone: 608-257-3911 / Fax: 608-257-0609) (Email: [email protected])

WISCONSIN PAPER COUNCIL Earl J. Gustafson PO Box 718 Neenah, WI 54957-0718 (Phone: 920-722-1500 / Fax: 920-722-7541) (Email: [email protected])

PUBLIC SERVICE COMMISSION OF WISCONSIN (Not a party, but documents must be filed with the Commission) 610 North Whitney Way P.O. Box 7854 Madison, WI 53707-7854 Please file documents using the Electronic Regulatory Filing (ERF) system which may be accessed through the PSC website: http://psc.wi.gov.

Courtesy Copy List:

Ritchie J. Sturgeon Wisconsin Power and Light Company PO Box 77007 Madison, WI 53707-1007 (Phone: 608-458-3951 / Fax: 608-458-4820) (Email: [email protected])

Dennis Dums Citizens Utility Board 16 North Carroll Street, Suite 530 Madison, WI 53703 (Phone: 608-251-3322 / Fax: 608-251-7609) (Email: [email protected])

Katie Nekola Clean Wisconsin 122 State Street, Suite 200 Madison, WI 53703-4333 (Phone: 608-251-7020 / Fax: 608-251-1655) (Email: [email protected])

Page 3 of 4 Docket 6680-CE-170 Exhibit ____ (RDB-1) Schedule 3

Chuck Thompson Dairyland Power Cooperative PO Box 817 La Crosse, WI 54602-0817 (Phone: 608-787-1432 / Fax: 608-787-1475) (Email: [email protected])

Todd Stuart Wisconsin Industrial Energy Group, Inc. 10 East Doty Street, Suite 800 Madison, WI 53703 (Phone: 608-441-5740 / Fax: 608-441-5741) (Email: [email protected]) g:\address\exam\servlist\6680-CE-170

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