Ms. Sandra J. Paske 

August 24, 2007 

Page 1 

August 24, 2007 

Ms. Sandra J. Paske 

Secretary to the Commission 

Public Service Commission of Wisconsin 

Post Office Box 7854 

Madison, WI 53707-7854 

RE: Supplement to Wisconsin Electric’s Application 

Oak Creek Power Plant Units 5, 6, 7, and 8 – Installation of Wet Flue Gas 

Desulfurization and Selective Catalytic Reduction Facilities and Associated 

Equipment for Control of Sulfur Dioxide and Nitrogen Oxide Emissions 

PSCW Docket No. 6630-CE-299 

Dear Ms. Paske: 

On June 21, 2007, Wisconsin Electric Power Company (“Wisconsin Electric” or the 

“Company”) submitted an application for authorization to install limestone based, forced 

oxidation, wet flue gas desulfurization ("WFGD") sulfur dioxide (“SO2”) control 

technology and selective catalytic reduction (“SCR”) nitrogen oxide (“NOx”) control 

technology on units 5, 6, 7, and 8 at Oak Creek Power Plant (the “Project”). Wisconsin 

Electric is submitting this supplement to our June 21st filing. 

 

Background 

By way of background, the Emissions Reduction Study (Appendix C filed with our 

application on June 21, 2007) identified two options for installing the SCR on a coal fired 

boiler. The traditional installation is the design at Pleasant Prairie Power Plant whereby 

the SCR is installed after the boiler economizer and before the boiler air heater. This 

design is referred to as “hot side design.” This option was eliminated from consideration 

due to higher total evaluated cost and more significant construction risks. 

The second option for installing the SCR is to install it after the boiler air heater and 

precipitator. There are two possible configurations for this design: (1) installing the SCR 

after the WFGD equipment (referred to as tail end design) and; (2) installing the SCR 

before the WFGD (cold side design). The Emission Reduction Study, Section 7.5, 

concluded that installing the WFGD, followed by the SCR (“tail end”) was the lowest 

total evaluated cost solution and the SCR followed by the WFGD configuration (“cold 

side” ) was a close second. However, the study also stated that the final choice should be 

the result of more detailed engineering. 

PSC REF#:81028 Public Service Commission of Wisconsin

RECEIVED: 08/24/07, 10:51:33 AM
Ms. Sandra J. Paske 

August 24, 2007 

Page 2 

Project Design Changes 

As part of the detailed design effort, it was determined that the tail end design has a 

higher cost than the cold side design. The increase in cost is caused primarily by design 

changes to support systems and associated annual O&M for the WFGD and SCR. Thus, 

this supplement requests authorization for the alternate cold side design. Included with 

this supplement are the following: 

• Highlighted revisions to supplement the application - Appendix A 

• Revised drawings depicting the cold side arrangement - Appendix B 

• Emission Reduction Study, Volume 1, Addendum August 20, 2007 - Appendix C 

The detailed design results (Appendix C) showed that the tail end configuration total 

evaluated cost is greater than anticipated in the conceptual design presented in the 

original Emissions Reduction Study, and the total evaluated cost for the cold side design 

was actually reduced. The following three observations resulting from the detailed 

design work shift the project in favor of the cold side arrangement: 

(1) The amount of steam required to reheat the flue gas increased significantly in 

the tail end design adversely affecting unit efficiency. The increase was a result 

of the need to provide supplemental steam to the WFGD heat exchanger which 

was not anticipated in the Emissions Reduction Study included with the original 

application. Since the cold side configuration does not require a heat exchanger 

for the WFGD, the total steam requirement is less for this arrangement. 

(2) The need to add supplemental steam to the tail end design requires the 

addition of steam heat exchangers which was not anticipated in the original 

application. This increased the capital cost estimate for the tail end configuration. 

(3) The SCR catalyst replacement costs were found to be lower than originally 

estimated for the cold side design. 

The capital cost estimate for the proposed cold side configuration is effectively the same 

as the previously filed cost estimate for the tail end system. While the cold side 

configuration does not require a FGD heat exchanger, it does require a larger SCR - as 

compared to the tail end design - which offsets the reduction in cost from the heat 

exchanger. Operating costs are slightly lower for the proposed cold side system but are 

within the accuracy of the original estimate and will not materially affect the EGEAS 

results. In addition to the change to a cold side arrangement, a further evaluation of the 

proposed installation of a CO catalyst in the flue gas was performed. After detailed 

discussions with several catalyst suppliers, the Company has now determined that the 

catalyst technology for this application, in either a tail end or cold end configuration, is 

not developed to the point that the catalyst can perform effectively, so it will not be 

installed as part of this project. As a result, the air permit application is being resubmitted 

to the WDNR. 
Ms. Sandra J. Paske 

August 24, 2007 

Page 3 

The Chapter 30 permit application will also require updates as a result of the proposed 

cold side configuration. Updated application materials will be submitted to the WDNR 

in early September. There are no changes to the environmental scope of the permit 

application or to the Chapter 30 authorizations being requested. 

Project Cost and Schedule 

The estimated total project cost is unchanged at $750 million. The cold end design capital 

cost is essentially the same as the tail end design proposed in the June 21, 2007 

application. However, the revised cost of the tail end design would have increased the 

total project cost by approximately $25 million if this change had not been proposed. The 

deletion of the CO catalyst, which was estimated a $1 million, has little effect on the 

overall project cost. With a lower cost estimate for periodic replacement/regeneration of 

the catalyst material in the cold side design, the EGEAS results are also unchanged. 

Since an order for the Project is not expected by the end of 2007, the current return for 

this project has been removed from the Company’s 2007 rate case which is currently 

being reviewed by the Commission. Thus the Company is requesting 100 percent 

AFUDC through 2009 for the Project. The revised AFUDC is now estimated as $80 

million, or a $10 million increase. 

In the Company’s June 21st application, Project approval was requested by January 1, 

2008. The Consent Decree requires that the units have controls installed by December 

31, 2012 or the units must be retired. An order in early 2008 reduces the risk that the 

December 31, 2012 deadline will be missed. While an earlier date is still desirable, the 

Company believes that an order by April 1, 2008 is sufficient to allow the substantial 

work that needs to be accomplished during the 2008 summer construction season to meet 

the December 31, 2012 in-service date. All other schedule times remain unchanged from 

the June 21st application. 

If you have any questions on this filing, please contact Paul Farron at (414) 221-3958. 

Very truly yours, 

Roman A. Draba 

Vice President, Regulatory Affairs and Policy 

cc: Mr. Scot Cullen – PSCW 

 Mr. Jim Lepinski - PSCW 

 Mr. Robert Norcross - PSCW 

 Mr. Dan Sage – PSCW 

 Mr. David Siebert – WDNR