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 Wisconsi n 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 Di oxide 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 (“SO 2 ”) control technology and selective catalytic re duction (“SCR”) nitrogen oxide (“NO

x ”) 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 21 st filing.

Background

By way of background, the Emissions Re duction Study (Appendix C filed with our application on June 21, 2007) identified two opt ions for installing the SCR on a coal fired

boiler. The traditional installation is the de sign 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 an d more significant c onstruction risks.

The second option for installing the SCR is to install it af ter the boiler air heater and precipitator. There are two po ssible configurations for this design: (1) installing the SCR after the WFGD equipment (referred to as ta il 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, followe d 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 al so stated that the final choice should be the result of more detailed engineering.Ms. Sandra J. Paske August 24, 2007 Page 2

Project Design Changes

As part of the detailed design effort, it wa s 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 aut horization for the alte rnate cold side design. Included with this supplement are the following:

• Highlighted revisions to supplem ent 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) show ed 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 resulti ng from the detailed design work shift the project in fa vor of the cold side arrangement:

(1) The amount of steam required to reheat the flue gas increas ed 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 stea m to the tail end design requires the addition of steam heat exchangers whic h was not anticipated in the original application. This increased th e capital cost estimate for th e 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 exch anger, 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 lowe r for the proposed cold side system but are within the accuracy of the original estimat e and will not materially affect the EGEAS results. In addition to the change to a cold side arrangeme nt, a further evaluation of the proposed installation of a CO catalyst in th e 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 proj ect. As a result, the air permit application is be ing 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 applicati on 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 uncha nged at $750 million. The cold end design capital cost is essentially the sa me as the tail end design proposed in the June 21, 2007 application. However, the revised cost of the tail end design woul d 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 expect ed 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 21 st application, Project approval was requested by January 1, 2008. The Consent Decree requi res that the units have c ontrols installed by December 31, 2012 or the units must be retired. An or der 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 al low the substantial work that needs to be accomplished during the 2008 summer construc tion season to meet the December 31, 2012 in-service date. All other schedule times remain unchanged from

the June 21 st application.

If you have any questions on this filing, pl ease contact Paul Fa rron 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