WISCONSIN ELECTRIC POWER CO - Quarter Report: 2006 September (Form 10-Q)

Nine Months Ended September 30

Wisconsin Electric Power Company

(Millions of Dollars)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2006

Commission	Registrant; State of Incorporation		IRS Employer
File Number	Address; and Telephone Number		Identification No.



001-01245	WISCONSIN ELECTRIC POWER COMPANY		39-0476280
		(A Wisconsin Corporation)
		231 West Michigan Street
		P.O. Box 2046
		Milwaukee, WI 53201
		(414) 221-2345

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [ ] Accelerated filer [ ] Non-accelerated filer [X].

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date (September 30, 2006):

Common Stock, $10 Par Value,

33,289,327 shares outstanding.

All of the common stock of Wisconsin Electric Power Company is owned by Wisconsin Energy Corporation.

		WISCONSIN ELECTRIC POWER COMPANY


		FORM 10-Q REPORT FOR THE QUARTER ENDED SEPTEMBER 30, 2006



		TABLE OF CONTENTS
Item			Page

	Introduction		3

	Part I -- Financial Information

1.	Financial Statements

	Consolidated Condensed Income Statements		4

	Consolidated Condensed Balance Sheets		5

	Consolidated Condensed Statements of Cash Flows		6

	Notes to Consolidated Condensed Financial Statements		7

2.	Management's Discussion and Analysis of
	Financial Condition and Results of Operations		17

3.	Quantitative and Qualitative Disclosures About Market Risk		35

4.	Controls and Procedures		35

	Part II -- Other Information

1.	Legal Proceedings		36

1A.	Risk Factors		37

6.	Exhibits		38

	Signatures		39

INTRODUCTION

Wisconsin Electric Power Company (Wisconsin Electric), a wholly-owned subsidiary of Wisconsin Energy Corporation (Wisconsin Energy), was incorporated in the state of Wisconsin in 1896. We maintain our principal executive offices in Milwaukee, Wisconsin. Unless qualified by their context when used in this document, the terms the Company, our, us or we refer to Wisconsin Electric and its subsidiary.

We conduct our operations primarily in three operating segments: an electric utility segment, a natural gas utility segment and a steam utility segment. We serve approximately 1,098,300 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 449,600 gas customers in Wisconsin and about 460 steam customers in metro Milwaukee, Wisconsin. For further financial information about our business segments, see Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 7 -- Segment Information in the Notes to Consolidated Condensed Financial Statements.

Wisconsin Energy is also the parent company of Wisconsin Gas LLC (Wisconsin Gas), a natural gas distribution utility, which serves customers throughout Wisconsin; Edison Sault Electric Company (Edison Sault), an electric utility which serves customers in the Upper Peninsula of Michigan; and W.E. Power, LLC (We Power), an unregulated company that was formed in 2001 to construct, own, and lease to us the new generating capacity included in Wisconsin Energy's Power the Future strategy, which is described further in this report and in our 2005 Annual Report on Form 10-K. We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies."

Other: Bostco LLC (Bostco) is our non-utility subsidiary that develops and invests in real estate. As of September 30, 2006, Bostco had $39.8 million of assets.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). We have condensed or omitted some information and note disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles pursuant to these rules and regulations. This Form 10-Q, including the financial statements contained herein, should be read in conjunction with our 2005 Annual Report on Form 10-K, including the financial statements and notes therein.

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

	WISCONSIN ELECTRIC POWER COMPANY
	CONSOLIDATED CONDENSED INCOME STATEMENTS
	(Unaudited)

				Three Months Ended		Nine Months Ended
				September 30		September 30

				2006	2005	2006	2005

				(Millions of Dollars)

	Operating Revenues			$745.2	$711.5	$2,303.7	$2,128.4

	Operating Expenses
		Fuel and purchased power		228.7	239.5	580.8	582.6
		Cost of gas sold		36.7	34.5	296.6	269.4
		Other operation and maintenance		264.0	216.9	796.3	663.7
		Depreciation, decommissioning
			and amortization	68.1	71.2	202.0	209.3
		Property and revenue taxes		21.6	19.2	65.0	59.6

	Total Operating Expenses			619.1	581.3	1,940.7	1,784.6


	Operating Income			126.1	130.2	363.0	343.8

	Equity in Earnings of Transmission Affiliate			8.5	7.7	25.2	22.8
	Other Income, Net			13.1	10.1	36.4	22.7

	Interest Expense			20.7	19.8	64.5	65.0


	Income Before Income Taxes			127.0	128.2	360.1	324.3

	Income Taxes			49.0	49.0	137.6	122.7


	Net Income			78.0	79.2	222.5	201.6

	Preferred Stock Dividend Requirement			0.3	0.3	0.9	0.9


	Earnings Available
		for Common Stockholder		$77.7	$78.9	$221.6	$200.7





	The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of
		these financial statements.

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED BALANCE SHEETS

			(Unaudited)
			September 30, 2006		December 31, 2005
			(Millions of Dollars)
Assets

Property, Plant and Equipment
	In service		$7,273.4		$7,152.4
	Accumulated depreciation		(2,889.7	)	(2,805.0	)

			4,383.7		4,347.4
	Construction work in progress		307.0		232.0
	Leased facilities, net		408.2		422.6
	Nuclear fuel, net		110.2		112.0

		Net Property, Plant and Equipment	5,209.1		5,114.0

Investments
	Nuclear decommissioning trust fund		839.8		782.1
	Equity investment in transmission affiliate		199.1		181.2
	Other		0.4		0.4

		Total Investments	1,039.3		963.7

Current Assets
	Cash and cash equivalents		14.9		23.2
	Accounts receivable		242.6		308.9
	Accrued revenues		125.9		175.6
	Materials, supplies and inventories		300.0		297.5
	Other		87.6		91.3

		Total Current Assets	771.0		896.5

Deferred Charges and Other Assets
	Regulatory assets		842.6		822.5
	Other		122.1		112.5

		Total Deferred Charges and Other Assets	964.7		935.0

Total Assets			$7,984.1		$7,909.2




Capitalization and Liabilities

Capitalization
	Common equity		$2,550.3		$2,310.9
	Preferred stock		30.4		30.4
	Long-term debt		1,289.8		1,290.1
	Capital lease obligations		528.3		536.0

		Total Capitalization	4,398.8		4,167.4

Current Liabilities
	Long-term debt and capital lease obligations due currently		216.1		232.4
	Short-term debt		180.7		352.7
	Accounts payable		221.7		293.9
	Accrued liabilities		176.0		147.0
	Other		140.0		106.5

		Total Current Liabilities	934.5		1,132.5

Deferred Credits and Other Liabilities
	Regulatory liabilities		1,095.7		1,051.9
	Asset retirement obligations		367.8		354.9
	Deferred income taxes - long-term		535.8		553.2
	Other		651.5		649.3

		Total Deferred Credits and Other Liabilities	2,650.8		2,609.3

Total Capitalization and Liabilities			$7,984.1		$7,909.2





The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of
	these financial statements.

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)

				Nine Months Ended September 30

				2006		2005

				(Millions of Dollars)
Operating Activities
	Net income			$222.5		$201.6
	Reconciliation to cash
		Depreciation, decommissioning and amortization		209.1		222.3
		Nuclear fuel expense amortization		22.1		16.6
		Equity in earnings of transmission affiliate		(25.2	)	(22.8	)
		Distributions from transmission affiliate		20.1		17.7
		Deferred income taxes and investment tax credits, net		(20.7	)	(1.6	)
		Change in -	Accounts receivable and accrued revenues	116.0		53.8
			Inventories	(2.5	)	(44.3	)
			Margin deposits	(17.9	)	-
			Other current assets	21.6		23.7
			Accounts payable	(67.6	)	16.3
			Accrued income taxes, net	16.3		41.7
			Deferred costs, net	(19.4	)	(91.0	)
			Other current liabilities	52.9		12.1
		Other		(29.3	)	13.2

Cash Provided by Operating Activities				498.0		459.3

Investing Activities
	Capital expenditures			(276.2	)	(275.0	)
	Investment in transmission affiliate			(12.8	)	-
	Nuclear fuel			(20.4	)	(13.5	)
	Nuclear decommissioning funding			(13.2	)	(13.2	)
	Proceeds from investments within nuclear decommissioning trust			430.8		337.5
	Purchases of investments within nuclear decommissioning trust			(430.8	)	(337.5	)
	Other			(0.3	)	1.2

Cash Used in Investing Activities				(322.9	)	(300.5	)

Financing Activities
	Dividends paid on common stock			(89.8	)	(134.7	)
	Dividends paid on preferred stock			(0.9	)	(0.9	)
	Issuance of long-term debt			-		21.4
	Retirement of long-term debt			(22.3	)	(18.8	)
	Change in short-term debt			(172.0	)	(41.7	)
	Capital contribution from parent			100.0		-
	Other, net			1.6		-

Cash Used in Financing Activities				(183.4	)	(174.7	)


Change in Cash and Cash Equivalents				(8.3	)	(15.9	)

Cash and Cash Equivalents at Beginning of Period				23.2		26.1


Cash and Cash Equivalents at End of Period				$14.9		$10.2




Supplemental Information - Cash Paid For
	Interest (net of amount capitalized)			$67.9		$60.3
	Income taxes (net of refunds)			$150.8		$84.6


The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of
	these financial statements.

WISCONSIN ELECTRIC POWER COMPANY
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)

1 -- GENERAL INFORMATION

Our accompanying unaudited consolidated condensed financial statements should be read in conjunction with Item 8, Financial Statements and Supplementary Data, in our 2005 Annual Report on Form 10-K. In the opinion of management, we have included all adjustments, normal and recurring in nature, necessary to a fair presentation of the results of operations, cash flows and financial position in the accompanying income statements, statements of cash flows and balance sheets. The results of operations for the three and nine months ended September 30, 2006 are not necessarily indicative of the results which may be expected for the entire fiscal year 2006 because of seasonal and other factors.

Modifications to Prior Statements: We have modified certain income statement and cash flows presentations. Prior year financial statement amounts have been reclassified to conform to their current year presentation. These reporting changes had no impact on total earnings or net cash provided by, or used in, operating, investing or financing activities.

We have also changed the presentation of the investing activities within our nuclear decommissioning trusts on the accompanying Consolidated Condensed Statements of Cash Flows to present proceeds from investments within the nuclear decommissioning trusts and purchases of investments within the nuclear decommissioning trusts. Previously, these items were excluded from the Consolidated Statements of Cash Flows as the nuclear decommissioning trusts are considered restricted investments. This reporting change had no impact on net cash provided by, or used in, operating, investing or financing activities.

Interim Accounting for Electric Fuel Revenues: For 2006, we will refund to customers any electric fuel revenues that we receive that are in excess of fuel and purchased power costs that we incur, as defined by the Wisconsin fuel rules. We do not recognize revenue for any amounts that are currently billable if it is probable that we will refund those amounts to customers. For additional information on the accounting for electric fuel revenues see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters.

2 -- COMMON EQUITY

Comprehensive Income: Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to owners. We recorded the following total comprehensive income during the nine months ended September 30, 2006 and 2005:

	Nine Months Ended September 30

Comprehensive Income	2006	2005

	(Millions of Dollars)

Net Income	$222.5	$201.6
Other Comprehensive Income (Loss)
Hedging	-	(0.8)

Total Other Comprehensive Income (Loss)	-	(0.8)

Total Comprehensive Income	$222.5	$200.8

Share-Based Compensation Plans: Our employees participate in the Wisconsin Energy 1993 Omnibus Stock Incentive Plan, as amended (OSIP), as approved by Wisconsin Energy stockholders. The OSIP enables Wisconsin Energy to provide a long-term incentive through equity interests in Wisconsin Energy, to outside directors, selected officers and key employees of Wisconsin Energy and its subsidiaries, including us. The OSIP provides for the granting of Wisconsin Energy stock options, stock appreciation rights, stock awards and performance shares. Awards may be paid in Wisconsin Energy common stock, cash or a combination thereof.

The exercise price of a Wisconsin Energy stock option under the OSIP is to be no less than 100% of the common stock's fair market value on the grant date and options may not be exercised within six months of the grant date except in the event of a change in control. In December 2004, the Compensation Committee of the Board of Directors of Wisconsin Energy (Compensation Committee) approved the acceleration of vesting of all unvested options awarded to executive officers and other key employees in 2002, 2003 and 2004. Options granted subsequent to December 31, 2004 are non-qualified stock options which vest on a cliff-basis after a three year period. Generally, options expire no later than ten years from the date of grant.

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (SFAS) 123R, Share-Based Payment, using the modified prospective method and using a binomial pricing model to estimate the fair value of stock options granted subsequent to December 31, 2005. Prior to January 1, 2006, we accounted for share based compensation under Accounting Principles Board Opinion 25 (APB 25), Accounting for Stock Issued to Employees, and Wisconsin Energy disclosed the pro forma impact of share based compensation expense under SFAS 123, Accounting for Stock-Based Compensation. Historically, all stock options have been granted with an exercise price equal to the fair market value of the common stock on the date of grant and expire no later than ten years from the grant date. Accordingly, no compensation expense was recognized in connection with option grants. All options granted subsequent to December 31, 2004 vest on a cliff-basis after a three year period. Wisconsin Energy allocates stock compensation expense to us based on the relative number of options granted to our employees. Prior to January 1, 2006, we reported benefits of tax deductions in excess of recognized compensation costs as operating cash flows. SFAS 123R requires that excess tax benefits be reported as a financing cash inflow rather than as an operating cash inflow.

We utilize the straight-line attribution method for recognizing stock-based compensation expense under SFAS 123R. We recorded compensation expense, net of tax, for stock option awards made to our employees of $1.1 million and $3.1 million for the three and nine months ended September 30, 2006. Tax benefits associated with our stock option awards for the three and nine months ended September 30, 2006 were $1.3 million and $2.4 million.

Results for the three and nine months ended September 30, 2005 have not been restated. Had compensation expense for all employee share based compensation been determined based on fair value at the grant date consistent with SFAS 123R, our net income for the three and nine months ended September 30, 2005 would have been reduced to the pro forma amounts indicated below.

	Three Months Ended September 30, 2005	Nine Months Ended September 30, 2005

	(Millions of Dollars)
Net Income
As reported	$79.2	$201.6
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	0.4	1.2
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	0.7	2.2

Pro forma	$78.9	$200.6

In the first nine months of 2006, the Compensation Committee granted 1,169,907 options to our employees that had an estimated weighted-average grant date fair value of $7.55 per share using a binomial option-pricing model. In the first nine months of 2005, the Compensation Committee granted 1,137,974 options to our employees that had an estimated grant date fair value of $8.32 per share using the Black-Scholes model. The following assumptions were used to value the Wisconsin Energy options in the indicated grant year:

	Grants

	2006	2005


Risk free interest rate	4.3% - 4.4%	4.4%
Dividend yield	2.4%	2.5%
Expected volatility	17% - 20%	19%
Expected life (years)	6.3	10

The risk-free interest rate is based on the U.S. Treasury interest rate whose term is consistent with the expected life of the stock options. Dividend yield, expected volatility and expected life assumptions, for 2006, are based on Wisconsin Energy's historical experience.

The following is a summary of Wisconsin Energy stock option activity held by our employees through the three and nine months ended September 30, 2006.

	Three Months		Nine Months

Stock Options	Number of Options	Weighted-Average Exercise Price	Number of Options	Weighted-Average Exercise Price


Outstanding at Beginning of Period	6,952,050	$30.88	5,960,727	$29.05
Granted	12,000	$42.56	1,169,907	$39.51
Exercised	(179,549)	$24.12	(346,133)	$24.54
Forfeited	(16,167)	$36.72	(16,167)	$36.72

Outstanding at September 30, 2006	6,768,334	$31.07	6,768,334	$31.07

The aggregate intrinsic value of Wisconsin Energy stock options exercised by our employees during the three and nine months ended September 30, 2006 was approximately $3.3 million and $6.0 million.

The following table summarizes information about Wisconsin Energy stock options outstanding and held by our employees at September 30, 2006:

	Options Outstanding			Options Exercisable

		Weighted-Average			Weighted-Average

			Remaining			Remaining
			Contractual			Contractual
		Exercise	Life		Exercise	Life
Range of Exercise Prices	Number	Price	(years)	Number	Price	(years)

$19.22 to $23.05	913,526	$21.65	4.7	913,526	$21.65	4.3
$25.31 to $27.65	1,448,434	$25.66	5.8	1,443,484	$25.66	5.8
$29.13 to $42.56	4,406,374	$34.80	7.8	2,120,311	$32.54	6.8

	6,768,334	$31.07	7.0	4,477,321	$28.10	6.0

Aggregate Intrinsic Value (Millions)

Options Outstanding

Options Exercisable

September 30, 2006

$81.7

$67.3

The following table summarizes the status of non-vested Wisconsin Energy options held by our employees for the three and nine months ended September 30, 2006:

	Three Months		Nine Months

		Weighted-		Weighted-
		Average		Average
		Fair		Fair
Non-Vested Stock Options	Number	Value	Number	Value


Non-vested - Beginning of Period	2,295,180	$7.93	1,150,820	$8.32
Granted	12,000	$7.69	1,169,907	$7.55
Vested	-	$ -	(13,547)	$7.61
Forfeited	(16,167)	$7.95	(16,167)	$7.95

Non-vested at September 30, 2006	2,291,013	$7.93	2,291,013	$7.93

The total fair value of options held by our employees and vesting during the three and nine months ended September 30, 2006 was zero and approximately $0.1 million. As of September 30, 2006, total compensation cost related to non-vested stock options not yet recognized was approximately $9.8 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

The Compensation Committee has also approved Wisconsin Energy restricted stock grants to certain key employees and directors. The following restricted stock activity related to our employees occurred during the three and nine months ended September 30, 2006:

	Three Months		Nine Months

		Weighted-		Weighted-
		Average		Average
		Market		Market
Restricted Shares	Number	Price	Number	Price


Outstanding at Beginning of Period	149,321		150,772
Granted	-	$ -	2,500	$40.35
Released / Forfeited	(1,923)	$29.13	(5,874)	$26.56

Outstanding at September 30, 2006	147,398		147,398

Recipients of the Wisconsin Energy restricted shares, who have the right to vote the shares and to receive dividends, are not required to provide consideration to us other than rendering service. Forfeiture provisions on the restricted stock generally expire 10 years after award grant, subject to an accelerated expiration schedule based on the achievement of certain financial performance goals.

Wisconsin Energy records the market value of the restricted stock awards on the date of grant. We then amortize our share of allocated expense over the vesting period of the awards. We also adjust expense for acceleration of vesting due to achievement of performance goals. We recorded compensation expense, net of tax, for restricted stock awards made to our employees and directors of $0.1 million and $0.2 million for the three and nine months ended September 30, 2006. Tax benefits realized for our restricted stock awards were approximately zero and $0.1 million for the three and nine months ended September 30, 2006. As of September 30, 2006, total compensation cost related to non-vested restricted stock awards not yet recognized was approximately $1.7 million, which is expected to be recognized over the next 64 months on a weighted-average basis.

In January 2004, the Compensation Committee granted 139,793 Wisconsin Energy performance shares to our officers and other key employees. In January 2006 and 2005, the Compensation Committee granted 134,818 and 90,739 Wisconsin Energy performance units to our officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of units which will be awarded is dependent upon the achievement of certain financial performance of Wisconsin Energy's common stock over a three year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance award. We are accruing compensation costs over the three year period based on our estimate of the final expected value of the award. In July 2006, the Compensation Committee amended the terms of the performance shares to allow the recipients of 2004 grants to receive cash or common stock upon settlement. The 2005 and 2006 grants will be settled in cash. We recorded compensation expense, net of tax, for performance awards made to our employees of $0.9 million and $2.3 million for the three and nine months ended September 30, 2006. We have not realized any tax benefits associated with our performance awards vesting during the three and nine months ended September 30, 2006. As of September 30, 2006, total compensation cost related to non‑vested performance awards not yet recognized was approximately $6.1 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

Restrictions: Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. In addition, under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. As of December 31, 2005, our restricted net assets were approximately $2.0 billion.

See Note H - Short-Term Debt in our 2005 Annual Report on Form 10-K for discussion of certain financial covenants related to our bank back-up credit agreements.

We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.

3 -- ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations under SFAS 143, Accounting for Asset Retirement Obligations, primarily relate to the future decommissioning costs for our Point Beach Nuclear Plant (Point Beach) and to asbestos related removal costs associated with other power plants. Our asset retirement obligations at September 30, 2006 were $367.8 million.

We adopted Financial Accounting Standards Board (FASB) Interpretation 47 (FIN 47), Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS 143, effective December 31, 2005. FIN 47 defines a conditional asset retirement obligation as a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The adoption of FIN 47 had no effect on net income due to the regulatory treatment of asset retirement costs.

If we had adopted interpretation FIN 47 at the beginning of fiscal 2005, we would have reported the following asset retirement obligations on our Consolidated Condensed Balance Sheets in "Asset Retirement Obligations."

Asset Retirement Obligations	September 30, 2006	December 31, 2005	December 31, 2004

	(Millions of Dollars)

Reported	$367.8	$354.9	$762.2
Pro forma	$367.8	$354.9	$798.4

The most significant asset retirement obligation is for Point Beach. The liability decreased significantly from December 31, 2004 to December 31, 2005 due to an updated Decommissioning Cost Study that had lower estimated costs to decommission the plant than the previous study. For further information regarding the change in the asset retirement obligation between December 31, 2005 and 2004 see Note F -- Nuclear Operations and Note I -- Asset Retirement Obligations in our 2005 Annual Report on Form 10-K.

4 -- DERIVATIVE INSTRUMENTS

We follow SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 149, an amendment of SFAS 133 on Derivative Instruments and Hedging Activities, which requires that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives under SFAS 133, the Public Service Commission of Wisconsin (PSCW) allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. As of September 30, 2006, we recognized $28.0 million in regulatory assets related to derivatives in comparison to $2.2 million at December 31, 2005.

5 -- BENEFITS

The components of our net periodic pension and other post-retirement benefit costs for the three and nine months ended September 30, 2006 and 2005 were as follows:

	Pension Benefits		Other Post-retirement Benefits
	Pension Benefits		Other Post-retirement Benefits

	2006	2005	2006	2005

	(Millions of Dollars)
Three Months Ended September 30
Net Periodic Benefit Cost
Service cost	$7.6	$7.5	$2.9	$3.4
Interest cost	14.9	14.8	3.5	4.4
Expected return on plan assets	(14.9)	(16.1)	(2.1)	(2.3)
Amortization of:
Transition obligation	-	(0.1)	0.1	0.3
Prior service cost (credit)	1.4	1.3	(3.3)	-
Actuarial loss	5.0	4.6	1.7	1.4

Net Periodic Benefit Cost	$14.0	$12.0	$2.8	$7.2

	Pension Benefits		Other Post-retirement Benefits
	Pension Benefits		Other Post-retirement Benefits

	2006	2005	2006	2005

	(Millions of Dollars)
Nine Months Ended September 30
Net Periodic Benefit Cost
Service cost	$22.9	$22.5	$8.8	$10.0
Interest cost	44.7	44.5	10.6	13.2
Expected return on plan assets	(44.9)	(48.3)	(6.5)	(6.8)
Amortization of:
Transition obligation	-	(0.1)	0.3	1.1
Prior service cost (credit)	4.1	3.9	(10.0)	-
Actuarial loss	15.2	13.5	5.2	4.1

Net Periodic Benefit Cost	$42.0	$36.0	$8.4	$21.6

In September 2006, we contributed $54.0 million to our qualified pension plans for the 2005 plan year.

Employee Benefit Plans and Post-retirement Benefits: In October 2005, we announced that we were offering to our retirees a Medicare Advantage program as an option within our existing post-retirement medical and drug plans. The Medicare Advantage program is part of the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The program offers post-65 medical and drug benefits through private insurance carriers. The Medicare Advantage program is expected to reduce the cost of post-65 medical and drug costs for our retirees and us. Due to this change, we remeasured the fair value of our other post-retirement plans in the fourth quarter of 2005 in accordance with SFAS 106, Employer's Accounting for Post-Retirement Benefits Other than Pensions. As a result of the Medicare Advantage program, our 2006 other post-retirement costs for the three and nine months ended September 30, 2006 are less than our 2005 costs in the comparative periods.

6 -- GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties. As of September 30, 2006, we had the following guarantees:

Maximum Potential Future Payments	Outstanding at September 30, 2006	Liability Recorded at September 30, 2006

(Millions of Dollars)

$235.2	$0.1	$ -

We guarantee the potential retrospective premiums that could be assessed under our nuclear insurance program.

Postemployment benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability, excluding severance benefits, for such benefits was $15.5 million as of September 30, 2006 and $12.8 million as of December 31, 2005.

7 -- SEGMENT INFORMATION

Summarized financial information concerning our reportable operating segments for the three and nine month periods ended September 30, 2006 and 2005 is shown in the following table.

Reportable Operating Segments

Electric	Gas	Steam	Total

(Millions of Dollars)

Three Months Ended


September 30, 2006
Operating Revenues (a)	$681.5	$59.0		$4.7		$745.2
Operating Income (Loss)	$131.1	($4.0	)	($1.0	)	$126.1

September 30, 2005
Operating Revenues (a)	$655.0	$53.3		$3.2		$711.5
Operating Income (Loss)	$139.3	($6.5	)	($2.6	)	$130.2

Nine Months Ended


September 30, 2006
Operating Revenues (a)	$1,878.4	$406.1		$19.2		$2,303.7
Operating Income	$337.4	$25.2		$0.4		$363.0

September 30, 2005
Operating Revenues (a)	$1,738.9	$372.5		$17.0		$2,128.4
Operating Income (Loss)	$323.7	$22.1		($2.0	)	$343.8

(a)	We account for all intersegment revenues at tariff rates established by the PSCW. Intersegment revenues are not material.

8 -- OTHER INCOME, NET

Other income, net includes the following items for the three and nine months ended September 30, 2006 and 2005:

	Three Months Ended September 30		Nine Months Ended September 30

Other Income, Net	2006	2005	2006	2005

	(Millions of Dollars)

Capitalized Carrying Costs	$6.1	$5.3	$18.7	$14.1
Allowance for Funds Used During Construction	4.1	2.5	11.3	6.1
Other, net	2.9	2.3	6.4	2.5

Total Other Income and Deductions	$13.1	$10.1	$36.4	$22.7

9 -- COMMITMENTS AND CONTINGENCIES

Environmental Matters: We periodically review our exposure for remediation costs as evidence becomes available indicating that our remediation liability has changed. Based on current information, we believe that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations.

10 -- NEW ACCOUNTING PRONOUNCEMENTS

FASB Staff Position FIN 46R - 6 (FSP FIN 46R - 6): In April 2006, the FASB issued FSP FIN 46R - 6, Determining the Variability to Be Considered in Applying FASB Interpretation No. 46R. FSP FIN 46R - 6 addresses the requirement to determine the variability to be considered in applying FASB Interpretation No. 46 based on an analysis of the design of the entity. Specifically, the FSP requires (1) an analysis of the nature of the risks in the entity and (2) a determination of the purpose(s) for which the entity was created and determination of the variability (created by the risks identified in Step 1) the entity is designed to create and pass along to its interest holders. As required, we adopted FSP FIN 46R - 6 effective July 1, 2006 for any new arrangements entered into after the effective date. Although we do not expect the adoption of FSP FIN 46R - 6 to have a material financial impact, we currently are unable to determine the potential impact in future periods.

FASB Interpretation No. 48 (FIN 48): In July 2006, the FASB issued FIN 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in the enterprise's financial statements in accordance with FASB Statement No. 109. FIN 48 provides clarification on the accounting for income taxes by setting forth a minimum recognition threshold an uncertain tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the provisions of FIN 48 and we expect to adopt FIN 48 on January 1, 2007.

SFAS No. 157, Fair Value Measurements (SFAS No. 157): In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 provides guidance for using fair value to measure assets and liabilities. SFAS No. 157 defines fair value, provides a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We are currently evaluating the provisions of SFAS No. 157 and we expect to adopt SFAS No. 157 on January 1, 2008.

SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Post-retirement Plans (SFAS No. 158): In September 2006, the FASB issued SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Post-retirement Plans, an amendment of FASB Statements Nos. 87, 88, 106 and 132(R). SFAS No. 158 requires recognition of the overfunded or underfunded status of a defined benefit post-retirement plan as an asset or liability on the balance sheet and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. SFAS No. 158 also requires an employer to measure the funded status of a plan as of the date of its year end balance sheet. We have historically, and will continue to use a year end measurement date for all of our pension and other post-retirement benefit plans. SFAS No. 158 is effective for financial statements issued for fiscal years ending after December 15, 2006. Prior to the issuance of SFAS No. 158, under current generally accepted accounting principles (GAAP), we record a minimum pension liability to reflect the funded status of our pension plans. We have concluded that substantially all of the unrecognized pension costs resulting from the recognition of our minimum pension liability that relate to our utility energy segment qualify as a regulatory asset. We are currently evaluating the provisions of

SFAS No. 158 and we expect to adopt SFAS No. 158 on December 31, 2006. Any changes in expense upon adoption are not expected to be material and we expect to defer the changes as regulatory assets or liabilities.

Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements (SAB No. 108): In September 2006, the SEC staff issued SAB No. 108. SAB No. 108 addresses the diversity in practice by registrants when quantifying the effect of an error on the financial statements. SAB No. 108 provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements. We will be required to adopt the provisions of SAB No. 108 effective December 31, 2006. We currently believe that the adoption of SAB No. 108 will not have a material financial impact on our consolidated financial statements.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

Cautionary Factors Regarding Forward - Looking Statements: Certain statements contained herein are "Forward-Looking Statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-Looking Statements include, among other things, statements regarding management's expectations and projections regarding completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. Also, Forward-Looking Statements may be identified by reference to a future period or periods or by the use of forward-looking terminology such as "anticipates," "believes," "estimates," "expects," "forecasts," "intends," "may," "objectives," "plans," "possible," "potential," "projects" or similar terms or variations of these terms. Actual results may differ materially from those set forth in Forward-Looking Statements as a result of certain risks and uncertainties, including but not limited to, those risks and uncertainties described in Item 1A. Risk Factors in Part II of this report and under the heading "Cautionary Factors" in this Item 2, other matters described under the heading "Factors Affecting Results, Liquidity and Capital Resources" in this Item 2, and other risks and uncertainties detailed from time to time in our filings with the SEC or otherwise described throughout this document.

RESULTS OF OPERATIONS -- THREE MONTHS ENDED SEPTEMBER 30, 2006

EARNINGS

We had net income of $78.0 million for the third quarter of 2006, a decrease of $1.2 million or 1.5% from the third quarter of 2005. Decreased net income primarily reflects milder summer weather during the third quarter of 2006 compared with the third quarter of 2005. In addition, there was an increase in operating and maintenance expenses which reflects the receipt of a settlement in a contract dispute with a vendor in the third quarter of 2005, which reduced other operating expenses in 2005. These were offset by some positive drivers, including (1) the implementation of new depreciation rates approved by the PSCW which reduced annual depreciation expenses and (2) increased equity Allowance for Funds Used During Construction (equity-AFUDC) between the comparative periods.

Electric Utility Revenues and Sales

The following table compares our electric utility operating revenues and megawatt-hour sales by customer class during the third quarter of 2006 with similar information for the third quarter of 2005 including favorable (better (B)) or unfavorable (worse (W)) variances.

Three Months Ended September 30

Electric Revenues

Megawatt-Hour Sales

2006

B(W)

2005

2006

B(W)

2005

(Millions of Dollars)

(Thousands)

Customer Class
Residential	$243.6	$13.6		$230.0	2,306.4	(39.5	)	2,345.9
Small Commercial/Industrial	216.5	11.7		204.8	2,439.1	(43.2	)	2,482.3
Large Commercial/Industrial	167.9	(2.3	)	170.2	2,876.7	(235.9	)	3,112.6
Other-Retail/Municipal	23.2	(6.0	)	29.2	496.0	(139.9	)	635.9
Resale-Utilities	19.3	2.2		17.1	282.8	53.5		229.3
Other Operating Revenues	11.0	7.3		3.7	-	-		-

Total	$681.5	$26.5		$655.0	8,401.0	(405.0	)	8,806.0




Weather -- Degree Days (a)
Cooling (524 Normal)					577	(96	)	673

(a)	As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.

Total electric utility operating revenues increased by $26.5 million, or 4.0%, when compared to the third quarter of 2005. We estimate that our third quarter 2006 revenues were $46.5 million higher than the third quarter of 2005 due to pricing increases that we received in January 2006 and during 2005. The most significant pricing increases authorized by the PSCW were to recover higher fuel and purchased power costs, capital costs associated with the new plants under Wisconsin Energy's Power the Future plan, and increased transmission costs. For more information on the pricing increases, see Utility Rates and Regulatory Matters in Factors Affecting Results, Liquidity and Capital Resources below.

Our electric sales volumes decreased by approximately 4.6% between the comparative periods. Residential sales volumes decreased due to milder summer weather in the third quarter of 2006. As measured by cooling degree days, the third quarter of 2006 was 14.3% cooler than the same period in 2005, decreasing cooling load sales to residential customers who are more weather sensitive and contribute higher margins than other customer classes. We estimate that weather had an unfavorable impact on operating revenues of approximately $5.5 million when compared to the prior year. Total sales volumes to commercial/industrial customers decreased 5.0% between comparative periods. Sales volumes to commercial/industrial customers, excluding our largest customers, two iron ore mines, decreased 2.3%. Sales volumes in the Other Retail/Municipal class decreased approximately 22.0% compared to the prior year due, in part, to the expiration of a wholesale contract on December 31, 2005.

Fuel and Purchased Power

Our fuel and purchased power expenses decreased by $10.8 million, or approximately 4.5%, when compared to the third quarter of 2005. The decrease is primarily due to the 4.6% reduction in megawatt-hour sales. Our cost of fuel and purchased power increased from $27.20 per megawatt-hour for the three months ended September 30, 2005 to $27.22 per megawatt-hour for the three months ended September 30, 2006. The higher cost per megawatt-hour was due to a 19.5% increase in the per

megawatt-hour cost of coal-fired generation, which includes coal and related transportation costs, between the comparative periods. Offsetting this increase was (1) a decrease in the average costs of purchased power and natural gas-fired units of approximately 8.3% between the comparative periods and (2) increased generation from our nuclear units. Nuclear unit output in 2005 was impacted by the completion of the spring nuclear refueling outage at Point Beach Unit 2 and the start of the scheduled fall nuclear refueling outage at Point Beach Unit 1. We did not have a nuclear refueling outage in the third quarter of 2006. The scheduled nuclear refueling outage for Point Beach Unit 2 began in October 2006.

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the third quarter of 2006 with similar information for the third quarter of 2005. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas margins increased by $3.5 million or 18.6%.

Three Months Ended September 30

2006	B (W)	2005

(Millions of Dollars)

Gas Operating Revenues	$59.0	$5.7		$53.3
Cost of Gas Sold	36.7	(2.2	)	34.5

Gross Margin	$22.3	$3.5		$18.8

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the third quarter of 2006 with similar information for the third quarter of 2005.

Three Months Ended September 30

Gross Margin

Therm Deliveries

2006

B (W)

2005

2006

B (W)

2005

(Millions of Dollars)

(Millions)

Customer Class
Residential	$14.3	$2.5	$11.8	22.0	(0.6	)	22.6
Commercial/Industrial	4.0	0.5	3.5	14.9	(0.4	)	15.3
Interruptible	0.1	-	0.1	0.9	-		0.9

Total Retail Gas Sales	18.4	3.0	15.4	37.8	(1.0	)	38.8
Transported Gas	3.5	0.4	3.1	71.2	(20.6	)	91.8
Other	0.4	0.1	0.3	-	-		-

Total	$22.3	$3.5	$18.8	109.0	(21.6	)	130.6



Weather -- Degree Days (a)
Heating (133 Normal)				128	75		53

(a)	As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.

The increase in gross margin is due primarily to a pricing increase that was granted by the PSCW and implemented in January 2006. The gas pricing increase was granted to recover higher operating costs, including bad debt expenses. Our gross margin increased between the comparative periods by approximately $3.6 million due to this pricing increase.

The decrease in volume of transport gas sales was due to a lower amount of electric generation from natural gas within our service territory due to milder weather in the third quarter of 2006.

Other Operation and Maintenance Expenses

Our other operation and maintenance expenses increased by $47.1 million, or 21.7%, when compared to the third quarter of 2005. As discussed above, we received pricing increases in January 2006 and during 2005 to cover increased costs. Our increases in other operation and maintenance expenses that relate to the pricing increases include increased Power the Future lease costs of $17.7 million and increased transmission expenses of $14.6 million. Other operation and maintenance expenses increased approximately $2.8 million due primarily to the timing of scheduled outages and maintenance projects at our coal plants. In addition, in the third quarter of 2005 we received approximately $10.0 million as a settlement in a contract dispute with a vendor, reducing other operation and maintenance expense in the third quarter of 2005.

Depreciation, Decommissioning and Amortization

Depreciation, Decommissioning and Amortization expenses decreased by $3.1 million or 4.4% when compared to the third quarter of 2005. In January 2006, we implemented new depreciation rates approved by the PSCW which reduced annual depreciation expenses. The decline was partially offset by increased depreciation expenses on plant additions.

Other Income, Net

Other income, net increased by $3.0 million or 29.7% when compared to the third quarter of 2005. The change relates primarily to increased equity-AFUDC of $1.6 million between the comparative periods.

Interest Expense

Interest expense increased by $0.9 million in the three months ended September 30, 2006 compared with the same period in 2005. Our interest costs increased primarily due to higher interest rates on both long-term and short-term debt.

Income Taxes

For the third quarter of 2006, our effective tax rate was 38.6% compared with a 38.2% rate during the third quarter of 2005.

RESULTS OF OPERATIONS -- NINE MONTHS ENDED SEPTEMBER 30, 2006
EARNINGS

We had net income of $222.5 million for the first nine months of 2006, an increase of $20.9 million or 10.4% from the first nine months of 2005. Net income increased primarily due to improved recovery of fuel costs, the timing of scheduled refueling outages at Point Beach Nuclear Plant and increased gas margins. In the first nine months of 2006, we did not have a scheduled nuclear refueling outage. We had two scheduled refueling outages in the first nine months of 2005. Point Beach Unit 2 has a scheduled

refueling outage which began in October of 2006. These increases were offset, in part, due to a weather-related decrease in retail electric sales and increased operation and maintenance expenses due to Port Washington Generating Station Unit 1 (PWGS 1) operating costs and the timing of scheduled outages and maintenance projects at our coal plants. A more detailed analysis of our financial results follows.

Electric Utility Revenues and Sales

The following table compares our electric utility operating revenues and megawatt-hour sales by customer class during the first nine months of 2006 with similar information for the first nine months of 2005 including favorable (better (B)) or unfavorable (worse (W)) variances.

Nine Months Ended September 30

Electric Revenues

Megawatt-Hour Sales

2006

B(W)

2005

2006

B(W)

2005

(Millions of Dollars)

(Thousands)

Customer Class
Residential	$645.2	$32.5		$612.7	6,122.2	(227.3	)	6,349.5
Small Commercial/Industrial	595.2	47.2		548.0	6,756.8	(35.6	)	6,792.4
Large Commercial/Industrial	478.5	22.0		456.5	8,347.6	(382.0	)	8,729.6
Other-Retail/Municipal	64.2	(13.2	)	77.4	1,499.9	(361.2	)	1,861.1
Resale-Utilities	66.2	36.6		29.6	1,279.3	755.0		524.3
Other Operating Revenues	29.1	14.4		14.7	-	-		-

Total	$1,878.4	$139.5		$1,738.9	24,005.8	(251.1	)	24,256.9




Weather -- Degree Days (a)
Heating (4,335 Normal)					3,834	(398	)	4,232
Cooling (708 Normal)					720	(190	)	910

(a)	As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.

Total electric utility operating revenues increased by $139.5 million, or 8.0%, when compared with the first nine months of 2005. We estimate that revenues in the first nine months of 2006 were $148.6 million higher than the same period in 2005 due to pricing increases that we received in January 2006 and during 2005. The most significant pricing increases authorized by the PSCW were to recover higher fuel and purchased power costs, capital costs associated with the new plants under Wisconsin Energy's Power the Future plan, and increased transmission costs. For more information on the pricing increases, see Utility Rates and Regulatory Matters in Factors Affecting Results, Liquidity and Capital Resources below.

Our electric sales volumes decreased by 1.0% as compared to the same period last year. Excluding sales volumes to other utilities, total electric sales volumes decreased 4.2% between the comparative periods. The increase in sale volumes to other utilities is attributed to the availability of PWGS 1 for the entire nine month period ended September 30, 2006, which provided additional generation capacity. PWGS 1 was not operational until the third quarter of 2005. Under the Wisconsin fuel rules, sales to other utilities reduce fuel costs charged to customers. Residential sales volumes decreased 3.6% due largely to weather. In the first nine months of 2006, heating degree days decreased approximately 9.4% compared to the same period in 2005 and cooling degree days decreased approximately 20.9%. We estimate that the weather had an unfavorable impact on operating revenues of approximately $32.8 million when compared to the prior year. Total sales volumes to commercial/industrial customers decreased 2.7%

between the comparative periods. Sales volumes to commercial/industrial customers, excluding our largest customers, two iron ore mines, decreased 1.1%.Sales volumes in the Other Retail/Municipal class decreased approximately 19.4% compared to the prior year due, in part, to the expiration of a wholesale contract on December 31, 2005.

Fuel and Purchased Power

Our fuel and purchased power expenses decreased by $1.8 million, or approximately 0.3%, when compared to the first nine months of 2005. Our cost of fuel and purchased power increased from $24.02 per megawatt-hour for the nine months ended September 30, 2005 to $24.19 per megawatt-hour for the nine months ended September 30, 2006. The largest factor for the higher cost per megawatt-hour was the 24.5% increase in the per megawatt-hour cost of coal-fired generation, which includes coal and related transportation costs, between the comparative periods. This increase was offset by (1) a decrease in the average costs of purchased power and natural gas-fired units of approximately 1.5% between the comparative periods and (2) increased generation from our nuclear units. Nuclear unit output in 2005 was impacted by the completion of the spring nuclear refueling outage at Point Beach Unit 2 and the start of the scheduled fall nuclear refueling outage at Point Beach Unit 1. We did not have a nuclear refueling outage in the first nine months of 2006. The scheduled nuclear refueling outage for Point Beach Unit 2 began in October 2006.

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the first nine months of 2006 with similar information for the first nine months of 2005. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas margins increased by $6.4 million or 6.2%.

Nine Months Ended September 30

2006	B (W)	2005

(Millions of Dollars)

Gas Operating Revenues	$406.1	$33.6		$372.5
Cost of Gas Sold	296.6	(27.2	)	269.4

Gross Margin	$109.5	$6.4		$103.1

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the first nine months of 2006 with similar information for the first nine months of 2005.

Nine Months Ended September 30

Gross Margin

Therm Deliveries

2006

B (W)

2005

2006

B (W)

2005

(Millions of Dollars)

(Millions)

Customer Class
Residential	$72.1	$5.1		$67.0	206.3	(23.7	)	230.0
Commercial/Industrial	23.9	1.2		22.7	127.5	(6.9	)	134.4
Interruptible	0.4	-		0.4	3.9	(0.1	)	4.0

Total Retail Gas Sales	96.4	6.3		90.1	337.7	(30.7	)	368.4
Transported Gas	11.3	(0.2	)	11.5	222.1	(52.6	)	274.7
Other	1.8	0.3		1.5	0.3	-		0.3

Total	$109.5	$6.4		$103.1	560.1	(83.3	)	643.4



Weather -- Degree Days (a)
Heating (4,335 Normal)					3,834	(398	)	4,232

(a)	As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.

The increase in gross margin is due, in part, to a pricing increase that was granted by the PSCW and implemented in January 2006. The gas pricing increase was primarily granted to recover higher operating costs, including bad debt expenses. Our gross margin increased between the comparative periods by approximately $12.6 million due to this pricing increase. We anticipate that the 2006 annual impact of the rate increase on our gas margins would be approximately $19.1 million under normal customer usage; however, we believe that the actual amount may be lower due to reduced customer usage.

The pricing increase was partially offset by a decline in gas sales volumes that was driven by mild winter weather and by lower customer usage. Temperatures (as measured by heating degree days) were approximately 9.4% warmer compared to the first nine months of 2005. The mild winter weather reduced customer demand for heating. We estimate that the weather decreased our gross margin by approximately $5.2 million between the comparative periods. With the increase in natural gas prices, we have experienced a reduction in the normalized use of gas per customer, decreasing our gross margin. The decrease in volume of transport gas sales was due to a lower amount of electric generation from natural gas within our service territory due to milder weather in the first nine months of 2006.

Other Operation and Maintenance Expenses

Our other operation and maintenance expenses increased by $132.6 million, or 20.0%, when compared to the first nine months of 2005. As discussed above, we received pricing increases in January 2006 and during 2005 to cover increased costs. Our increases in other operation and maintenance expenses that relate to the pricing increases include increased Power the Future lease costs of $68.2 million and increased transmission expenses of $45.2 million. Other operation and maintenance expenses increased approximately $15.3 million due to PWGS 1 operating costs and the timing of scheduled outages and maintenance projects at our coal plants. In the first nine months of 2006, we did not have a scheduled nuclear refueling outage as was experienced in the second and third quarters of 2005, which resulted in a decrease of approximately $10.6 million in nuclear operation and maintenance expenses between the comparative periods. In addition, in 2005 we received approximately $10.0 million as a settlement in a contract dispute with a vendor, reducing other operation and maintenance expense in the first nine

months of 2005. These increases were offset, in part, by the elimination of seams elimination transmission charges, effective March 31, 2006, which resulted in reduced costs of approximately $7.4 million for the first nine months of 2006. For further information on seams elimination charges, see Electric Transmission in Factors Affecting Results, Liquidity and Capital Resources below.

Depreciation, Decommissioning and Amortization

Depreciation, Decommissioning and Amortization expenses decreased by $7.3 million or 3.5% when compared to the first nine months of 2005. In January 2006, we implemented new depreciation rates approved by the PSCW which reduced annual depreciation expenses. The decline was partially offset by increased depreciation expenses on plant additions.

Other Income, Net

Other income, net increased by $13.7 million when compared to the first nine months of 2005. The largest increase relates to increased equity-AFUDC and capitalized carrying costs of $9.8 million.

Interest Expense

Interest expense decreased by $0.5 million in the nine months ended September 30, 2006 when compared with the same period in 2005. In the first nine months of 2005, we expensed approximately $6.2 million related to the amortization of costs associated with prior debt redemptions. These costs were fully amortized as of July 2005; therefore, there was no similar expense in the first nine months of 2006. In addition, this decrease reflects increased capitalized interest in 2006 due to a higher average balance of construction projects in 2006. These decreases were offset by higher interest rates on both long-term and short-term debt, as well as increased average balances of commercial paper outstanding.

Income Taxes

For the first nine months of 2006, our effective tax rate was 38.2% compared with a 37.8% rate during the first nine months of 2005.

LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS

The following summarizes our cash flows during the first nine months of 2006 and 2005:

Cash Provided by (Used in)
Operating Activities	$498.0		$459.3
Investing Activities	($322.9	)	($300.5	)
Financing Activities	($183.4	)	($174.7	)

Operating Activities

Cash provided by operating activities for the nine months ended September 30, 2006 totaled $498.0 million, which is a $38.7 million improvement over the same period last year. There were two primary areas that drove this improvement in operating cash flows. First, during 2006 we had favorable fuel recoveries of $56.7 million, which is a $121.1 million improvement over 2005 fuel recoveries. During the fourth quarter of 2006, we will refund back to customers approximately $32 million of the favorable fuel recoveries. For further information on fuel recoveries, see Utility Rates and Regulatory Matters --Electric Rates in Factors Affecting Results, Liquidity and Capital Resources below. The second positive driver relates to gas in storage. During 2006, we entered into certain contracts that reduced our need to inject gas in storage. We estimate that this reduced our cash needs for gas in storage by approximately $16.2 million. Partially offsetting these items was an increase of cash taxes of approximately $66.2 million due to higher taxable earnings.

Investing Activities

During the nine months ended September 30, 2006, cash used in investing activities was $322.9 million, an increase of $22.4 million over the same period in 2005. This increase was due primarily to increased investment in our transmission affiliate. In addition, expenditures associated with nuclear fuel purchases were higher during the first nine months of 2006.

Financing Activities

During the nine months ended September 30, 2006, we used $183.4 million for financing activities compared with using $174.7 million for financing activities during the same period in 2005. The primary uses of cash for financing activities during the first nine months of 2006 and 2005 were to reduce short-term debt and to pay dividends on common stock. For the first nine months of 2006, these uses were partially offset by a $100 million capital contribution from Wisconsin Energy in April 2006.

CAPITAL RESOURCES AND REQUIREMENTS
Capital Resources

We anticipate meeting our capital requirements during the remaining nine months of 2006 primarily through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities depending on market conditions and other factors. In addition, as mentioned above, we received a $100 million capital contribution from Wisconsin Energy in April 2006. Beyond 2006, we anticipate meeting our capital requirements through internally generated funds supplemented, when required, by the issuance of debt securities.

We have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We believe that we have adequate capacity to fund our operations for the foreseeable future through our borrowing arrangements and internally generated cash.

We have been evaluating the possible issuance of environmental trust bonds for some time. However, after extensive evaluation and analysis, we will not be pursuing an issuance of environmental trust bonds.

We expect to retire at the scheduled maturity date, $200 million of 6-5/8% debentures due November 15, 2006. We anticipate issuing up to $300 million of debentures during the fourth quarter of 2006 off an existing $665 million shelf registration statement filed with the SEC, subject to market conditions and other factors.

We have a credit agreement that provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes.

As of September 30, 2006, we had approximately $497.9 million of available unused lines of bank back-up credit facilities on a consolidated basis and approximately $180.7 million of total consolidated short-term debt outstanding.

We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. The following table summarizes our facility at September 30, 2006:

Total Facility	Letters of Credit	Credit Available	Facility Expiration	Facility Term

(Millions of Dollars)

$500.0	$2.1	$497.9	March 2011	5 year

The following table shows our consolidated capitalization structure at September 30, 2006 and at December 31, 2005:

Capitalization Structure	September 30, 2006	December 31, 2005

	(Millions of Dollars)

Common Equity	$2,550.3	53.2%	$2,310.9	48.6%
Preferred Stock	30.4	0.6%	30.4	0.6%
Long-Term Debt (a)	1,489.9	31.1%	1,493.0	31.5%
Capital Lease Obligations (a)	544.3	11.3%	565.5	11.9%
Short-Term Debt	180.7	3.8%	352.7	7.4%

Total	$4,795.6	100.0%	$4,752.5	100.0%



(a) Includes current maturities

Access to capital markets at a reasonable cost is determined in large part by credit quality. The following table summarizes the ratings of our debt securities and preferred stock by Standard & Poors Corporation (S&P), Moody's Investors Service (Moody's) and Fitch Ratings (Fitch) as of September 30, 2006.

	S&P	Moody's	Fitch

Commercial Paper	A-2	P-1	F1
Secured Senior Debt	A-	Aa3	AA-
Unsecured Debt	A-	A1	A+
Preferred Stock	BBB	A3	A

On June 15, 2006, Fitch affirmed our security ratings. Our security ratings outlook assigned by Fitch is stable.

On June 8, 2006, S&P affirmed our security ratings and ratings outlook. Our security ratings outlook assigned by S&P is negative.

Our security ratings outlook assigned by Moody's is stable.

We believe these security ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.

Capital Requirements

Capital requirements during the remainder of 2006 are expected to be principally for construction expenditures, long-term debt maturities and nuclear fuel. Our 2006 annual capital expenditure budget, excluding the purchase of nuclear fuel and expenditures for new generating capacity contained in Wisconsin Energy's Power the Future strategy, is approximately $444.0 million.

Off-Balance Sheet Arrangements: We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support commodity contracts and other payment obligations. We continue to believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For further information, see Note 6 -- Guarantees in the Notes to Consolidated Condensed Financial Statements in this report.

We have identified three tolling and purchased power agreements with third parties but have been unable to determine if we are the primary beneficiary of any of these three variable interest entities as defined by FASB Interpretation 46, Consolidation of Variable Interest Entities (FIN 46). As a result, we do not consolidate these entities. Instead, we account for one of these contracts as a capital lease and for the other two contracts as operating leases. For additional information, see Note D -- Variable Interest Entities in our 2005 Annual Report on Form 10-K. We have included our contractual obligations under all three of these contracts in our evaluation of Contractual Obligations/Commercial Commitments discussed below.

Contractual Obligations/Commercial Commitments: Our total contractual obligations and other commercial commitments increased to approximately $6.2 billion as of September 30, 2006 compared with $5.8 billion as of December 31, 2005. Contractual obligations increased primarily due to purchase obligations under new coal supply contracts, gas supply contracts and nuclear contracts for uranium, enrichment and fabrication. This increase was partially offset by periodic payments made in the ordinary course of business during the nine months ended September 30, 2006.

FACTORS AFFECTING RESULTS, LIQUDITY AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity and capital resources. The following discussion should be read together with the information under the heading "Factors Affecting Results, Liquidity and Capital Resources" in Item 7 of our 2005 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, Wisconsin Energy's Power the Future strategy, utility rates and regulatory matters, electric system reliability, environmental matters, legal matters, nuclear operations, industry restructuring and competition and other matters.

MARKET RISKS AND OTHER SIGNIFICANT RISKS

Credit Rating Risk: We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. We do have certain agreements in the form of commodity and energy services contracts and employee benefit plans that could require, in the event of a credit ratings change to below investment grade, a termination payment if collateral is not provided or an accelerated payment. At September 30, 2006, we estimate that the potential payments under these agreements that could result from credit rating downgrades totaled approximately $61.5 million.

POWER THE FUTURE

Under Wisconsin Energy's Power the Future strategy, we expect to meet a significant portion of our future generation needs through the leasing of the PWGS and the Oak Creek expansion, which are being constructed by We Power. We will lease the new plants from We Power under long-term leases, and we expect to recover the lease payments in our electric rates. See Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7 of our 2005 Annual Report on Form 10-K for additional information on Power the Future.

Port Washington: Construction of the second gas-fired unit is well underway. Site preparation, including removal of the old coal units at the site, was completed early this year, and most of the major components have been procured for the second unit at PWGS. The unit is expected to begin commercial operation in time for the peak summer season in 2008.

Oak Creek Expansion: The Certificate of Public Convenience and Necessity (CPCN) granted for the construction of the Oak Creek expansion was the subject of a number of legal challenges by third parties; these legal challenges were resolved in June 2005. In June 2005, construction commenced at the site. We have received all permits necessary to commence construction. Certain of these permits continue to be contested, but remain in effect unless and until overturned by a reviewing court or administrative law judge.

The Wisconsin Department of Natural Resources (WDNR) Chapter 30 permit for wetlands and waterways alterations and construction on the bed of Lake Michigan for the construction of the Oak Creek expansion was the subject of legal challenges. The permit was issued following a contested case proceeding and was subsequently appealed to the Circuit Court for Dane County. The circuit court dismissed the challenge on procedural grounds. In February 2006, the Wisconsin Court of Appeals affirmed the lower court's decision dismissing the case. The period for appeal of that decision to the Wisconsin Supreme Court has expired.

A contested case hearing for the Wisconsin Pollutant Discharge Elimination System permit was held in March 2006. The administrative law judge upheld the issuance of the permit in a decision issued in July 2006. In August 2006, the opponents filed in Dane County Circuit Court for judicial review of the administrative law judge's decision upholding the issuance of the permit. Briefing has been scheduled to be completed in December 2006. We anticipate a decision in 2007.

UTILITY RATES AND REGULATORY MATTERS

In January 2006, the PSCW issued an order that increased our electric, gas and steam rates effective January 26, 2006. We anticipate that these base rates will remain in effect through December 2007. A discussion of this order follows.

Electric Rates: In January 2006, we received an order from the PSCW that allowed us to increase annual electric revenues by approximately $222.0 million to recover increased costs associated with investments in Wisconsin Energy's Power the Future units, transmission services and fuel and purchased power, as well as costs associated with additional sources of renewable energy. The order also required us to refund to customers, with interest, any fuel revenues that we receive that are in excess of fuel and purchased power costs that we incur, as defined by the Wisconsin fuel rules. Any refund would also include interest at short-term rates. This refund provision does not extend past December 31, 2006.

During 2006, we experienced lower than expected fuel and purchased power costs and in September 2006, we requested and received approval from the PSCW to refund approximately $32 million in favorable fuel recoveries including accrued interest at short-term rates. The refunds are being issued as a credit on customer bills beginning in late September 2006. The PSCW will perform a final review of fuel recoveries for the year ending December 31, 2006 and any additional favorable recoveries would be refunded with interest during 2007. In September 2006, the PSCW determined that if the total favorable recoveries for 2006 exceeded $36 million, interest on the favorable recoveries in excess of $36 million would be paid at the rate of 11.2% rather than at short-term rates as originally set forth in the order. Our authorized return on equity under the January 2006 order is 11.2%.

For 2007, we expect to operate under a traditional fuel cost adjustment clause in the Wisconsin retail jurisdiction whereby fuel revenues may be adjusted prospectively if fuel and purchased power costs fall outside a pre-established annual band of plus or minus 2%.

Gas Rates: Our gas operations went through a traditional rate proceeding whereby the revenues were set to recover projected costs and to provide a return on rate base. The January 2006 order provided for an increase in gas revenues of $21.4 million which was based on an authorized return on equity of 11.2%.

Steam Rates: The steam rate proceeding was a traditional rate proceeding. The January 2006 order provided for an increase in steam rates of $7.8 million to be phased in over a two year period beginning in 2006. The rate increase was based on an authorized return on equity of 11.2%.

2005 Fuel Recovery Filing: In 2005, we received a rate increase of $122.6 million (6.2%) for the increased costs of fuel and purchased power as a result of customer growth and the increase in the reliance upon natural gas as a fuel source. In December 2005, two parties filed suit against the PSCW in Dane County Circuit Court challenging the PSCW's decision to allow fuel cost recovery, while allowing us to keep the savings that resulted from the WICOR acquisition. As a condition of the PSCW approval of the WICOR acquisition, we were restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain limited exceptions, but we were allowed to keep the savings generated from the merger. In July 2006, the Dane County Circuit Court affirmed the PSCW's decision. In August 2006, the opponents appealed this decision. We anticipate a decision from the Court of Appeals in 2007.

Midwest Independent Transmission System Operator, Inc.'s (MISO) bid-based energy market (MISO Midwest Market): In March 2005, we submitted a joint proposal to the PSCW with other utilities requesting escrow accounting treatment for the MISO Midwest Market costs until each utility's first rate case following April 1, 2008. The purpose of the March 2005 request for escrow accounting was to provide clarification on costs not included in the previous approval for deferral accounting treatment. The PSCW approved deferral treatment for these costs in June 2006.

Wholesale Electric Rates: On August 1, 2006, we filed a wholesale rate case with the Federal Energy Regulatory Commission (FERC). The filing requests an annual increase in rates of approximately $16.7 million applicable to four of our existing wholesale electric customers. We anticipate a decision by the end of the year.

See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters in Item 7 of our 2005 Annual Report on Form 10-K for additional information regarding our utility rates, the MISO Midwest Market and other regulatory matters.

Public Utility Holding Company Act of 2005 (PUHCA 2005)

We were an exempt holding company under the Public Utility Holding Company Act of 1935 (PUHCA 1935), and, accordingly, were exempt from that law's provisions other than with respect to certain acquisitions of securities of a public utility. However, the Energy Policy Act of 2005 repealed PUHCA 1935 and enacted PUHCA 2005, transferring jurisdiction over holding companies from the SEC to the FERC. In March 2006, we filed with the FERC notification of our status as a holding company as required under the FERC regulations implementing PUHCA 2005 and a request for exempt status similar to that held under PUHCA 1935. In June 2006, we received notice from the FERC confirming our status as a holding company as required under the FERC regulations implementing PUHCA 2005 and granting exempt status similar to that held under PUHCA 1935.

Renewables, Efficiency and Conservation

In March 2006, Wisconsin enacted new public benefits legislation, 2005 Wisconsin Act 141 (Act), that changes the renewable energy requirements for utilities. The Act establishes a statewide mandate for energy required from renewable sources of no less than 5% by 2010 and 10% by 2015 of total retail energy delivered. We must obtain approximately 210 megawatts of additional renewable capacity by 2010 and another approximately 610 megawatts of additional renewable capacity by 2015 to meet the retail energy delivered requirements. We have already started development of additional sources of renewable energy to comply with commitments made as part of Wisconsin Energy's Power the Future initiative which will assist us in complying with the Act. See Wind Generation discussion below.

The Act allows the PSCW to delay implementation of the renewable portfolio standard if it finds that achieving the renewable requirement would be too expensive or would lessen reliability, or that new renewable projects could not be permitted on a timely basis or could not be served by adequate transmission facilities. The previous law did not include similar provisions. The Act provides that if a utility is in compliance with the renewable energy and energy efficiency requirements as determined by the PSCW, then the utility is considered in compliance with the Energy Priority Law. Prior to this Act, there had been no agreement on how to determine compliance with the Energy Priority Law.

We are evaluating the requirements of the Act. Additionally, the details of the new requirements are subject to administrative rulemaking that could take until March 2007 to complete.

The Act also redirects the administration of energy efficiency, conservation and renewable programs from the State Department of Administration back to the utilities and/or contracted third parties. In addition, the law requires that 1.2% of utilities' operating revenues be set aside for these programs. We do not expect the impact of this action to be material as the 1.2% approximates the amounts currently in our rates for these matters. The effective date of this action is July 1, 2007. The PSCW is expected to develop implementation plans over the upcoming months.

Wind Generation

In June 2005, we purchased the development rights to two wind farm projects (Blue Sky Green Field) from Navitas Energy Inc. We plan to develop the wind sites and construct wind turbines with a combined generating capacity of between approximately 130 to 200-megawatts. We filed for approval of a CPCN with the PSCW in March 2006. A prehearing conference was held in September 2006. In addition, our direct testimony was filed in September 2006. Staff and intervenor testimony is due in

October 2006 and rebuttal testimony by all parties is due in November 2006. Hearings are scheduled for the end of November 2006. We anticipate a final decision in the first quarter of 2007. In addition to the CPCN approval, we are working to secure any additional permits necessary to commence construction. Recently, the United States Congress directed the Department of Defense and the Department of Homeland Security to investigate possible conflicts between military radar and wind turbine installations. We have not been informed that Blue Sky Green Field poses such a conflict, but we are working with the Federal Aviation Administration and the United States Air Force to confirm that there are no conflicts.

We estimate that the capital cost of the project, excluding AFUDC, will be up to $360 million. The demand for wind turbine equipment has been strong, pushing off equipment deliveries to dates later than originally anticipated. We currently expect the turbines to be placed in service between 2008 and 2009, dependent upon the availability of wind turbines and the receipt of necessary regulatory approvals.

NUCLEAR OPERATIONS

We own two 518-megawatt electric generating units (Unit 1 and Unit 2) at Point Beach Nuclear Plant (Plant) in Two Rivers, Wisconsin. The Plant is operated by Nuclear Management Company, LLC (NMC), a joint venture of the Company and affiliates of other unaffiliated utilities. In February 2006, we announced that we were undertaking a formal review regarding our options for the ownership and operation of Point Beach. The options that we have been evaluating include: (1) continued operation by NMC, (2) continued operation by a third party operator other than NMC, (3) a return to in-house operation of the Plant by us and (4) the sale of the Point Beach facility. In addition, we are now also evaluating a partial sale of the Point Beach facility with us retaining a minority interest in the facility. In this case, the new majority owner would operate Point Beach. As part of our continuing review, we invited qualified third parties to tour Point Beach and review the data necessary to submit a bid to either own or operate the Plant. We will evaluate the bids received for full or partial sale in comparison to continued operation of Point Beach by NMC or by us. We expect to complete this formal review in the fourth quarter of 2006. If it is determined that NMC would no longer operate the Point Beach facility, we would be obligated to pay an exit fee to NMC of approximately $12 million.

Each Unit at the Plant has a scheduled refueling outage approximately every 18 months. In October 2006, our scheduled refueling outage began at Unit 2. The outage is scheduled to be completed in the fourth quarter of 2006. In 2005 we had two scheduled outages. In 2005, the Unit 2 outage was over the second and third quarters and the Unit 1 outage was over the third and fourth quarters. During the 2005 scheduled refueling outages we replaced the reactor vessel heads in each Unit. This work, along with other planned maintenance, resulted in longer than normal outages. During scheduled refueling outages, we incur significant operations and maintenance costs for work performed during the outages and we incur costs associated with replacement power.

See Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations in Item 7 of our 2005 Annual Report on Form 10-K for additional information regarding our nuclear operations.

ELECTRIC TRANSMISSION

Effective April 1, 2005, we began participating in the MISO Midwest Market which changed how our generating units are dispatched and how we buy and sell power.

In MISO, base transmission costs are currently being paid by load serving entities (LSEs) located in the service territories of each MISO transmission owner. FERC also ordered a seams elimination charge to be paid by MISO LSEs from December 1, 2004 until March 31, 2006, to compensate transmission owners for the loss of revenues resulting from the joining of a Regional Transmission

Organization (RTO) and/or FERC's elimination of through and out transmission charges between the MISO and PJM Interconnection, L.L.C. The details of the seams elimination charge and the quantification of the existing transaction charge are the subject of a hearing process initiated by FERC in a February 2005 order. In January 2006, along with certain other parties to the proceeding, we submitted an offer of settlement to the presiding administrative law judge that resolved all issues set for hearing that impact us with regard to the continued payment of through and out transmission charges as well as the seams elimination charge. The administrative law judge certified the settlement to the FERC, and the FERC approved the settlement on April 13, 2006.

As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the locational marginal price (LMP) system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through the use of Financial Transmission Rights (FTRs). FTRs are allocated to market participants by MISO. A new allocation of FTRs was completed for the period of June 1, 2006 through May 31, 2007. We were granted substantially all of the FTRs that we were permitted to request during the allocation process. As previously disclosed in our 2005 Form 10-K, our unhedged congestion costs had not been material; however, due to certain changes in the units that MISO is dispatching, our unhedged congestion costs have increased in 2006. These incremental congestion charges are deferred as approved by the PSCW, and we expect to recover these costs in future rates, subject to review and approval by the PSCW.

In April 2006, the FERC issued an order determining that MISO had not applied its energy markets tariff correctly in the assessment of Revenue Sufficiency Guarantee charges. The FERC ordered MISO to resettle all affected transactions retroactive to April 1, 2005. The FERC's order has been challenged by MISO and numerous other market participants. We expect a final ruling from the FERC by the end of 2006. Any resettlement associated with the order is expected in 2007. Due to the complexity of the order, we are unable to precisely determine the overall financial implication to us. However, we do not believe that the result will have a material impact on our results of operations.

See Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Electric Transmission and Energy Markets -- in Item 7 of our 2005 Annual Report on Form 10-K for additional information regarding MISO.

ENVIRONMENTAL MATTERS

Clean Air Interstate Rule (CAIR): The United States Environmental Protection Agency (EPA) issued the final CAIR regulation in March 2005 to facilitate the states in meeting the 8-hour ozone and PM _2.5 standards by addressing the regional transport of SO₂ and NO_x. CAIR requires NO_x and SO₂ emission reductions in two phases from electric generating units located in a 28-state region within the eastern United States. Wisconsin and Michigan are affected states under CAIR. The phase 1 compliance deadline is January 1, 2009 for NO_x and January 1, 2010 for SO₂, and the phase 2 compliance deadline is January 1, 2015 for both NO_x and SO₂. Overall, the CAIR is expected to result in a 70% reduction in SO₂ emissions and a 65% reduction in NO_x emissions from 2002 emission levels. The states are required to develop and submit implementation plans by no later than March 2007, and until those plans are in place, it is not possible to estimate the impact of the CAIR. We believe that compliance with the NO_x and SO₂ emission reductions requirements under our existing agreements with the WDNR and EPA will substantially mitigate costs to comply with the CAIR rule.

See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 of our 2005 Annual Report on Form 10-K for additional information regarding environmental matters.

OTHER MATTERS

Pension Reform: In August 2006, the President signed the Pension Protection Act of 2006 (PPA). We are currently evaluating the PPA, but we do not anticipate the PPA will have a material impact on our results of operations or cash flows from operating activities.

ACCOUNTING DEVELOPMENTS - NEW PRONOUNCEMENTS

See Note 10 -- New Accounting Pronouncements in the Notes to Consolidated Condensed Financial Statements in this report for a discussion of recently issued accounting pronouncements and the potential impact, upon adoption, on our consolidated financial statements.

CAUTIONARY FACTORS

This report and other documents or oral presentations contain or may contain forward-looking statements made by or on behalf of Wisconsin Electric. These statements are based upon management's current expectations and are subject to risks and uncertainties that could cause our actual results to differ materially from those contemplated in the statements. Readers are cautioned not to place undue reliance on the forward-looking statements. Forward-looking statements include, among other things, statements regarding management's expectations and projections regarding completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. When used in written documents or oral presentations, the terms "anticipates," "believes," "estimates," "expects," "forecasts," "intends," "may," "objectives," "plans," "possible," "potential," "projects" and similar expressions are intended to identify forward-looking statements. In addition to the assumptions and other factors referred to specifically in connection with these statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statements or otherwise affect our future results of operations and financial condition include, among others, the following:

Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related or terrorism-related damage; availability of electric generating facilities; unscheduled generation outages, or unplanned maintenance or repairs; unanticipated events causing scheduled generation outages to last longer than expected; unanticipated changes in fossil fuel, nuclear fuel, purchased power, coal supply, gas supply or water supply costs or availability due to higher demand, shortages, transportation problems or other developments; nonperformance by electric energy or natural gas suppliers under existing power purchase or gas supply contracts; nuclear or environmental incidents; resolution of used nuclear fuel storage and disposal issues; electric transmission or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; collective bargaining agreements with union employees or work stoppages; inflation rates; or demographic and economic factors affecting utility service territories or operating environment.

Regulatory factors such as unanticipated changes in rate-setting policies or procedures; unanticipated changes in regulatory accounting policies and practices; industry restructuring initiatives; transmission or distribution system operation and/or administration initiatives; recovery of costs of previous investments made under traditional regulation; recovery of costs associated with adoption of changed accounting standards; required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities; required approvals for new construction; changes in the United States Nuclear Regulatory Commission's regulations related to Point Beach Nuclear Plant or a permanent repository for used nuclear fuel; changes in the regulations of the United States Environmental Protection Agency as well as the Wisconsin Department of Natural Resources or the

33

Michigan Department of Environmental Quality, including but not limited to regulations relating to the release of emissions from fossil-fueled power plants such as carbon dioxide, sulfur dioxide, nitrogen oxide, small particulates or mercury; the siting approval process for new generation and transmission facilities; recovery of costs associated with implementation of a bid-based energy market; or changes in the regulations from the Wisconsin Department of Natural Resources related to the siting approval process for new pipeline construction.

The changing electric and gas utility environment as market-based forces replace strict industry regulation and other competitors enter the electric and gas markets resulting in increased wholesale and retail competition.

Unanticipated operational and/or financial consequences related to implementation of the Midwest Independent Transmission System Operator, Inc. bid-based energy market that started in April 2005.

Consolidation of the industry as a result of the combination and acquisition of utilities in the Midwest, nationally and globally as a result of the repeal of the Public Utility Holding Company Act of 1935 or otherwise.

Factors which impede execution of Wisconsin Energy's Power the Future strategy, including receipt of necessary state and federal regulatory approvals, timely and successful resolution of legal challenges, local opposition to siting of new generating facilities, construction risks, including the adverse interpretation or enforcement of permit conditions by the permitting agencies, and obtaining the investment capital from outside sources necessary to implement the strategy.

Changes in social attitudes regarding the utility and power industries.

Customer business conditions including demand for their products or services and supply of labor and material used in creating their products and services.

The cost and other effects of legal and administrative proceedings, settlements, investigations and claims and changes in those matters.

Factors affecting the availability or cost of capital such as: changes in interest rates and other general capital market conditions; our capitalization structure; market perceptions of the utility industry or us; or security ratings.

Federal, state or local legislative factors such as changes in tax laws or rates; changes in trade, monetary and fiscal policies, laws and regulations; electric and gas industry restructuring initiatives; changes in the Price-Anderson Act; changes in environmental laws and regulations; or changes in allocation of energy assistance, including state public benefits funds.

Implementation of the Energy Policy Act of 2005 and the effect of state level proceedings and the development of regulations by federal and other agencies, including the Federal Energy Regulatory Commission, as well as the ultimate authorization of the Federal Energy Regulatory Commission to allow us to lease the three Power the Future units that are currently being constructed by We Power.

Authoritative generally accepted accounting principle or policy changes from such standard setting bodies as the Financial Accounting Standards Board, the Securities and Exchange Commission and the Public Company Accounting Oversight Board.

Unanticipated technological developments that result in competitive disadvantages and create the potential for impairment of existing assets.

Other business or investment considerations that may be disclosed from time to time in our Securities and Exchange Commission filings or in other publicly disseminated written documents.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

*****

For certain other information which may impact our future financial condition or results of operations, see Item 1. Financial Statements -- Notes to Consolidated Condensed Financial Statements, in Part I of this report as well as Item 1. Legal Proceedings and Item 1A. Risk Factors, in Part II of this report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For information concerning market risk exposures at Wisconsin Electric Power Company, see Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks in Part I of this report and in Part I of Wisconsin Electric's Quarterly Reports on Form 10-Q for the periods ended March 31, 2006 and June 30, 2006. For information concerning other market risk exposures, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks, in Part II of Wisconsin Electric's 2005 Annual Report on Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures: Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this report. Based upon such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective (i) in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting: There has not been any change in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the fiscal quarter to which this report relates that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2005 Annual Report on Form 10-K and Item 1. Legal Proceedings in Part II of our Quarterly Report on Form 10-Q for the periods ended March 31, 2006 and June 30, 2006.

In addition to those legal proceedings discussed in our reports to the SEC, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these legal proceedings cannot be predicted with certainty, we believe, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material adverse effect on our financial condition.

UTILITY RATES AND REGULATORY MATTERS

See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Part I of this report for information concerning rate matters in the jurisdictions where we do business.

Power the Future: See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Part I of this report for information concerning Wisconsin Energy's Power the Future strategy.

OTHER MATTERS

Stray Voltage: In recent years, several actions by dairy farmers have been commenced or claims made against us for loss of milk production and other damages to livestock allegedly caused by stray voltage resulting from the operation of our electrical system.

On February 26, 2004, a Wisconsin jury awarded $850,000 to a dairy farmer who alleged that our distribution system caused damages to his livestock. We appealed this decision. In April 2006, the Wisconsin Court of Appeals affirmed the jury's verdict against us awarding $1.3 million, including interest and costs, to the plaintiffs in this suit.

In May 2005, a stray voltage lawsuit was filed against us. We do not believe the lawsuit has merit and we will vigorously defend the case. The trial for this matter is scheduled to begin in April 2007. This claim against us is not expected to have a material adverse effect on our financial condition or results of operations.

Even though any claims which may be made against us with respect to stray voltage and ground currents are not expected to have a material adverse effect on our financial condition, we continue to evaluate various options and strategies to mitigate this risk.

Arbitration Proceedings: Our largest electric customers, two iron ore mines, operate in the Upper Peninsula of Michigan. The mines represent approximately 7% of our annual electric sales; however, the earnings are insignificant to us. The mines have special negotiated contracts that expire in December 2007. The contracts have price caps for approximately 80% of the energy sales. We do not recognize revenue on amounts billed that exceed the price caps.

The incremental power costs in the Upper Peninsula of Michigan are now determined by MISO. In April 2005, we began to bill the mines the incremental power costs as quantified by the MISO Midwest Market. The mines have notified us that they are disputing these billings and a portion of these disputed amounts have been deposited in escrow. In September 2005, the mines notified us that they filed for formal arbitration related to the contracts. We have notified the mines that we believe that they have failed to comply with certain notification provisions related to annual production as specified within the contracts. The arbitration hearings previously scheduled for October 2006 have been postponed and rescheduled for June 2007, and we anticipate a decision in the second half of 2007. As of September 30, 2006, the mines have placed $29.3 million in escrow. As of December 31, 2005, the mines had placed $70.6 million in escrow. The decrease in the escrow balance relates to amounts that we refunded without interest for the amounts billed in 2005 that exceeded the price caps. At this time, we are unable to predict the outcome of the formal arbitration process, but we believe that it will not have a material impact on our financial condition or results of operations.

Milwaukee Solvay Coke and Gas Site: We responded to an EPA request for information pursuant to Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Section 104(e) for the Solvay Coke and Gas Site located in Milwaukee, Wisconsin. All potentially responsive records and corporate legal files have been reviewed and responsive information was provided in October 2004. A predecessor company of ours owned a parcel of property that is within the property boundaries of the site. In April 2006, we received a special notice letter from the EPA identifying us as a potentially responsible party and commencing a negotiation period with the EPA and other parties regarding the conduct of a Remedial Investigation and Feasibility Study (RI/FS) and reimbursement of the EPA's past costs. We, along with other parties, are currently negotiating with the EPA on the scope of work and terms of an administrative order on consent for performance of the RI/FS. The parties anticipate that investigation activities may commence in 2007. Although we are negotiating to perform the RI/FS pursuant to an administrative order on consent with the EPA, we do not admit to any liability for the site, waive any liability defenses, or commit to perform remedial activities at the site at this time. However, investigation and remediation cost estimates and reserves continue to be included in the estimated manufactured gas plant values reported in Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements contained in our 2005 Annual Report on Form 10-K.

ITEM 1A. RISK FACTORS
Restructuring in the regulated energy industry could have a negative impact on our business.

The regulated energy industry continues to experience significant structural changes. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant adverse financial impact on us. The timeline for restructuring and retail access continues to be stretched out, and it is uncertain when retail access will happen in Wisconsin; however, Michigan has adopted retail choice which potentially affects our Michigan operations. Under retail access legislation, customers are permitted to choose their own electric generation supplier. All Michigan electric customers were able to choose their electric generation supplier beginning in January 2002. Although competition and customer switching to alternative suppliers in our service territories in Michigan has been limited, the additional competitive pressures resulting from retail access could lead to a loss of customers and our incurring stranded costs.

The FERC continues to support the existing RTOs which affect the structure of the wholesale market within those RTOs. In connection with its status as a FERC approved RTO, MISO implemented the MISO Midwest Market on April 1, 2005. The MISO Midwest Market rules require that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes a LMP which reflects the market price for energy. As a participant in the

new MISO Midwest Market, we are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining stability of the transmission system.

Additionally, the MISO Midwest Market subjects us to additional costs primarily associated with constraints in the transmission system. MISO implemented the LMP system, a market-based platform for valuing transmission congestion. The LMP system includes the ability to mitigate or eliminate congestion charges through the use of FTRs. FTRs are allocated to market participants by MISO. A new allocation of FTRs was completed for the period of June 1, 2006 through May 31, 2007. We were granted substantially all of the FTRs that we were permitted to request during the allocation process. There can be no assurance that we will be granted an adequate level of FTRs in the future. As allowed by the PSCW, unhedged congestion charges have been deferred and we expect to recover these costs in future rates, subject to review and approval by the PSCW.

See Item 1A. Risk Factors in our 2005 Annual Report on Form 10-K for a discussion of additional risk factors applicable to us.

ITEM 6. EXHIBITS

Exhibit No.


12	Statements re Computation of Ratios

12.1	Statement of Computation of Ratio of Earnings to Fixed Charges.

31	Rule 13a-14(a) / 15d-14(a) Certifications

31.1	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32	Section 1350 Certifications

32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	WISCONSIN ELECTRIC POWER COMPANY
	(Registrant)

	/s/STEPHEN P. DICKSON
Date: October 27, 2006	Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer