Edgar Filing: WISCONSIN ENERGY CORP

2006 Q3 10-Q 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.



001-09057	WISCONSIN ENERGY CORPORATION		39-1391525
		(A Wisconsin Corporation)
		231 West Michigan Street
		P.O. Box 1331
		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 [X] Accelerated filer [ ] Non-accelerated filer [ ].

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, $.01 Par Value,

116,978,883 shares outstanding.

		WISCONSIN ENERGY CORPORATION


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		20

3.	Quantitative and Qualitative Disclosures About Market Risk		42

4.	Controls and Procedures		42

	Part II - Other Information

1.	Legal Proceedings		42

1A.	Risk Factors		44

2.	Unregistered Sales of Equity Securities and Use of Proceeds
	[and Issuer Purchases of Equity Securities]		45

6.	Exhibits		45

	Signatures		46

INTRODUCTION

Wisconsin Energy Corporation is a diversified holding company which conducts its operations primarily in two operating segments: a utility energy segment and a non-utility energy segment. Unless qualified by their context when used in this document, the terms Wisconsin Energy, the Company, our, us or we refer to the holding company and all of its subsidiaries. Our primary subsidiaries are Wisconsin Electric Power Company (Wisconsin Electric), Wisconsin Gas LLC (Wisconsin Gas) and W.E. Power, LLC (We Power).

Utility Energy Segment: Our utility energy segment consists of: Wisconsin Electric, which serves electric customers in Wisconsin and the Upper Peninsula of Michigan, gas customers in Wisconsin and steam customers in metro Milwaukee, Wisconsin; Wisconsin Gas, which serves gas customers in Wisconsin and water customers in suburban Milwaukee, Wisconsin; and Edison Sault Electric Company (Edison Sault), which serves electric customers in the Upper Peninsula of Michigan. Wisconsin Electric and Wisconsin Gas operate under the trade name of "We Energies."

Non-Utility Energy Segment: Our non-utility energy segment primarily consists of We Power. We Power was formed in 2001 to construct, own and lease to Wisconsin Electric the new generating capacity included in our Power the Future (PTF) strategy, which is described further in this report and in our 2005 Annual Report on Form 10-K.

Other: Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark LLC (Wispark). As of September 30, 2006, Wispark had $64.2 million of assets.

Discontinued Operations: Effective September 27, 2006, we sold 100% of the membership interests in Minergy Neenah, LLC (Minergy Neenah). Effective May 31, 2005, we sold our Calumet Energy (Calumet) facility, which was part of our non-utility energy segment. For further information, see Note 3 - Discontinued Operations and Assets Held for Sale in the Notes to Consolidated Condensed Financial Statements in this report.

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 (GAAP) 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 ENERGY CORPORATION
CONSOLIDATED CONDENSED INCOME STATEMENTS
(Unaudited)

				Three Months Ended		Nine Months Ended
				September 30		September 30

				2006	2005	2006	2005

				(Millions of Dollars, Except Per Share Amounts)

	Operating Revenues			$839.8	$797.3	$2,901.2	$2,680.5

	Operating Expenses
		Fuel and purchased power		229.8	240.5	583.8	584.9
		Cost of gas sold		85.1	80.3	695.1	633.0
		Other operation and maintenance		287.1	241.5	875.1	764.4
		Depreciation, decommissioning
			and amortization	82.0	84.6	243.4	245.4
		Property and revenue taxes		24.6	22.0	73.9	67.7

	Total Operating Expenses			708.6	668.9	2,471.3	2,295.4


	Operating Income			131.2	128.4	429.9	385.1

	Equity in Earnings of Transmission Affiliate			9.7	8.8	28.7	25.9
	Other Income, net			15.2	13.2	44.8	30.4
	Interest Expense			41.5	44.6	129.3	128.5


	Income from Continuing
		Operations Before Income Taxes		114.6	105.8	374.1	312.9

	Income Taxes			43.8	40.0	139.2	100.3

	Income from Continuing Operations			70.8	65.8	234.9	212.6

	Income from Discontinued
		Operations, Net of Tax (Note 3)		-	0.4	4.5	5.5


	Net Income			$70.8	$66.2	$239.4	$218.1




	Earnings Per Share (Basic)
			Continuing operations	$0.61	$0.57	$2.01	$1.82
			Discontinued operations	-	-	0.04	0.04

	Total Earnings Per Share (Basic)			$0.61	$0.57	$2.05	$1.86




	Earnings Per Share (Diluted)
			Continuing operations	$0.60	$0.56	$1.98	$1.80
			Discontinued operations	-	-	0.04	0.04

	Total Earnings Per Share (Diluted)			$0.60	$0.56	$2.02	$1.84




	Weighted Average Common
		Shares Outstanding (Millions)
			Basic	117.0	117.0	117.0	117.0
			Diluted	118.4	118.6	118.3	118.4

	Dividends Per Share of Common Stock			$0.23	$0.22	$0.69	$0.66

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

WISCONSIN ENERGY CORPORATION
CONSOLIDATED CONDENSED BALANCE SHEETS

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

Property, Plant and Equipment
	In service		$8,973.4	$8,849.6
	Accumulated depreciation		(3,395.6)	(3,288.5)

			5,577.8	5,561.1
	Construction work in progress		1,056.0	596.6
	Leased facilities, net		89.0	93.2
	Nuclear fuel, net		110.2	112.0

		Net Property, Plant and Equipment	6,833.0	6,362.9

Investments
	Nuclear decommissioning trust fund		839.8	782.1
	Equity investment in transmission affiliate		226.2	205.8
	Other		46.2	92.1

		Total Investments	1,112.2	1,080.0

Current Assets
	Cash and cash equivalents		21.2	73.2
	Accounts receivable		278.3	441.8
	Accrued revenues		141.2	262.9
	Materials, supplies and inventories		427.7	451.6
	Prepayments and Other		108.0	130.1
	Assets held for sale		-	17.4

		Total Current Assets	976.4	1,377.0

Deferred Charges and Other Assets
	Regulatory assets		1,074.3	1,025.6
	Goodwill, net		441.9	441.9
	Other		186.4	174.6

		Total Deferred Charges and Other Assets	1,702.6	1,642.1

Total Assets			$10,624.2	$10,462.0




Capitalization and Liabilities

Capitalization
	Common equity		$2,834.6	$2,680.1
	Preferred stock of subsidiary		30.4	30.4
	Long-term debt		3,034.8	3,031.0

		Total Capitalization	5,899.8	5,741.5

Current Liabilities
	Long-term debt due currently		218.2	496.0
	Short-term debt		709.3	456.3
	Accounts payable		278.6	418.1
	Accrued liabilities		154.2	134.4
	Other		181.0	142.0

		Total Current Liabilities	1,541.3	1,646.8

Deferred Credits and Other Liabilities
	Regulatory liabilities		1,424.5	1,373.2
	Asset retirement obligations		368.4	355.5
	Deferred income taxes - long-term		579.4	593.7
	Other		810.8	751.3

		Total Deferred Credits and Other Liabilities	3,183.1	3,073.7

Total Capitalization and Liabilities			$10,624.2	$10,462.0





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

WISCONSIN ENERGY CORPORATION
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)

				Nine Months Ended September 30

				2006	2005

				(Millions of Dollars)
Operating Activities
	Net income			$239.4	$218.1
	Reconciliation to cash
		Depreciation, decommissioning and amortization		250.2	261.4
		Nuclear fuel expense amortization		22.1	16.6
		Equity in earnings of transmission affiliate		(28.7)	(25.9)
		Distributions from transmission affiliate		22.9	20.2
		Deferred income taxes and investment tax credits, net		(25.5)	70.5
		Deferred revenue		53.2	43.9
		Change in -	Accounts receivable and accrued revenues	285.2	158.9
			Inventories	23.9	(101.1)
			Margin deposits	(26.9)	-
			Other current assets	22.6	25.4
			Accounts payable	(151.3)	28.1
			Accrued income taxes, net	28.7	(69.2)
			Deferred costs, net	(29.4)	(91.9)
			Other current liabilities and Other	21.7	7.8
	Operating cash flows provided by discontinued operations			0.2	1.2

Cash Provided by Operating Activities				708.3	564.0

Investing Activities
	Capital expenditures			(664.0)	(503.1)
	Investment in transmission affiliate			(14.6)	-
	Proceeds from asset sales, net			69.0	61.6
	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			(6.9)	(1.9)
	Investing cash flows used in discontinued operations			(0.2)	(1.2)

Cash Used in Investing Activities				(650.3)	(471.3)

Financing Activities
	Exercise of stock options			12.5	44.1
	Purchase of common stock			(21.8)	(70.3)
	Dividends paid on common stock			(80.7)	(77.2)
	Issuance of long-term debt			10.0	153.0
	Retirement of long-term debt			(285.3)	(7.9)
	Change in short-term debt			253.0	(140.2)
	Other, net			2.3	-

Cash Used in Financing Activities				(110.0)	(98.5)


Change in Cash and Cash Equivalents				(52.0)	(5.8)

Cash and Cash Equivalents at Beginning of Period				73.2	35.6


Cash and Cash Equivalents at End of Period				$21.2	$29.8




Supplemental Information - Cash Paid For
	Interest (net of amount capitalized)			$125.2	$107.7
	Income taxes (net of refunds)			$139.1	$97.7


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

WISCONSIN ENERGY CORPORATION
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 per share.

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, Wisconsin Electric will refund to customers any electric fuel revenues that it receives that are in excess of fuel and purchased power costs that it incurs, 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 - Rates and Regulatory Matters.

2 - ACCOUNTING AND REPORTING FOR POWER THE FUTURE GENERATING UNITS

Background: As part of our PTF strategy, our non-utility subsidiary, We Power, is building four new generating units that will be leased to our utility subsidiary, Wisconsin Electric, under long-term leases that have been approved by the Public Service Commission of Wisconsin (PSCW), our primary regulator. The leases are designed to recover the capital costs of the plant including a return. The first of the four generating units was placed in service in July 2005 and is being leased to Wisconsin Electric. Wisconsin Electric will be responsible for all of the operating costs, including fuel, of the PTF units once they are placed in service and we anticipate that we will recover the operating costs of these plants in rates. The accompanying consolidated financial statements eliminate all intercompany transactions between We Power and Wisconsin Electric, and reflect the cash inflows from Wisconsin Electric customers and the cash outflows to our vendors and suppliers.

The PTF units include Port Washington Generating Station Unit 1 and Unit 2 (PWGS 1 and PWGS 2) and Oak Creek expansion Unit 1 and Unit 2 (OC 1 and OC 2).

During Construction: Under the terms of each lease, we collect in current rates amounts representing our pre-tax cost of capital (debt and equity) associated with capital expenditures for the PTF units. Our

pre-tax cost of capital is approximately 14%. The carrying costs that we collect in rates are recorded as deferred revenue, and they will be amortized to revenue over the term of each lease, once the respective unit is placed into service. During the construction of the PTF units, we capitalize interest costs at an overall weighted-average pre-tax cost of interest of approximately 6%. Capitalized interest is included in the total cost of the PTF units.

The following table identifies key pre-tax cash outflows and inflows related to the construction of our PTF units for the nine months ended September 30, 2006 and 2005.

	Capital Expenditures (Millions of Dollars)				Total

Nine Months Ended Sept. 30,	PWGS 1	PWGS 2	OC 1	OC 2	PTF	WEC

2006	$ -	$94.7	$189.9	$61.2	$345.8	$664.0
2005	$48.6	$30.9	$86.8	$23.4	$189.7	$503.1

	Capitalized Interest (Millions of Dollars)				Total

Nine Months Ended Sept. 30,	PWGS 1	PWGS 2	OC 1	OC 2	PTF	WEC

2006	$ -	$5.5	$12.8	$4.6	$22.9	$27.1
2005	$10.8	$1.8	$4.9	$1.9	$19.4	$22.1

	Deferred Carrying Costs (Millions of Dollars)				Total

Nine Months Ended Sept. 30,	PWGS 1	PWGS 2	OC 1	OC 2	PTF	WEC

2006	$ -	$12.6	$29.9	$10.7	$53.2	$53.2
2005	$23.9	$4.1	$11.4	$4.5	$43.9	$43.9

Balance Sheet: As noted above, we collect in current rates carrying costs that are calculated based on the cash expenditures included in Construction Work in Progress (CWIP) multiplied by our pre-tax cost of capital (approximately 14%). The carrying costs are recorded as deferred revenue and included in Other Long-term Liabilities. Our total CWIP balance includes cash expenditures, capitalized interest and accruals. The following table identifies key amounts related to our PTF units that are recorded on our balance sheet as of September 30, 2006 and December 31, 2005:

	CWIP - Cash Expenditures (Millions of Dollars)				Total

As of	PWGS 1	PWGS 2	OC 1	OC 2	PTF

September 30, 2006	$ -	$170.5	$398.0	$135.9	$704.4
December 31, 2005	$ -	$67.5	$198.9	$74.9	$341.3

	Total CWIP (Millions of Dollars)				Total

As of	PWGS 1	PWGS 2	OC 1	OC 2	PTF	WEC

September 30, 2006	$ -	$179.2	$421.1	$144.5	$744.8	$1,056.0
December 31, 2005	$ -	$70.7	$209.2	$78.9	$358.8	$596.6

	Net Plant in Service (Millions of Dollars)				Total

As of	PWGS 1	PWGS 2	OC 1	OC 2	PTF	WEC

September 30, 2006	$352.5	$ -	$ -	$ -	$352.5	$5,577.8
December 31, 2005	$359.9	$ -	$ -	$ -	$359.9	$5,561.1

	Deferred Revenue Included in Other Long-term Liabilities (Millions of Dollars)				Total

As of	PWGS 1	PWGS 2	OC 1	OC 2	PTF	WEC

September 30, 2006	$69.0	$21.1	$50.4	$19.3	$159.8	$159.8
December 31, 2005	$71.2	$8.5	$20.6	$8.5	$108.8	$108.8

Income Statement: Once the PTF units are placed in service, we will recover in rates the lease costs which reflect the authorized cash construction cost of the units plus a return. The authorized cash costs

are established by the PSCW. The authorized cash costs exclude capitalized interest since carrying costs are recovered during the construction of the units. The lease payments are expected to be levelized, except that the OC units will be recovered on a levelized basis that has a one time 10.6% escalation after the first 5 years of the leases. The leases established a set return on equity component of 12.7% and a set interest rate, which will be established when each unit is placed into service.

We recognize revenues related to the lease payments that are included in our rates. In addition, our revenues will include the amortization of the deferred revenues that reflect the carrying costs that are collected during construction. The deferred revenue will be amortized on a straight line basis over the lease term. We will depreciate the units on a straight line basis over their expected service life.

In July 2005, PWGS 1 was placed in service. This asset had a cost of approximately $364.3 million which included approximately $31.1 million of capitalized interest. The asset is being depreciated over its estimated useful life of approximately 37 years. The cost of the plant, plus a return, is expected to be recovered through Wisconsin Electric's rates over a 25 year period at an annual amount of approximately $48 million.

3 - DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

The earnings of the assets identified below are reflected in discontinued operations in the accompanying Consolidated Condensed Income Statements. The combined operating revenues for these operations were approximately $3.6 million and $4.6 million for the three months ended September 30, 2006 and 2005, and approximately $14.3 million and $15.7 million for the nine months ended September 30, 2006 and 2005.

Minergy Neenah: In September 2006, we sold 100% of the membership interests in Minergy Neenah to Fox Valley Energy Holdings, LLC, an affiliate of Thermagen Power Group, LLC.

The primary assets of Minergy Neenah were a Glass Aggregate Plant and related operating contracts. The plant recycles paper sludge from paper mills into electricity, steam and a glass aggregate product. The largest source of revenue for Minergy Neenah had been a long-term steam contract with an adjacent paper mill owned by P.H. Glatfelter Company (Glatfelter). Glatfelter permanently closed the mill as of June 30, 2006. Pursuant to the steam contract, Glatfelter paid Minergy Neenah a contract termination payment.

In the third quarter of 2006, we received gross proceeds from the sale of the plant and the contract termination totaling $12.2 million and we recorded a net loss of $0.2 million that is included in Income from Discontinued Operations, net.

Pursuant to the terms of the sale agreement, we have agreed to customary indemnification provisions related to post-closing obligations and other matters. Our maximum aggregate exposure under the indemnification provisions is $0.3 million.

Wisvest - Calumet: Effective May 31, 2005, we sold our Calumet facility for approximately $37.0 million in cash to Tenaska Power Fund, L.P. (Tenaska). The primary assets of Calumet were a 308 - megawatt natural gas-fired peaking power facility in Chicago, Illinois and related operating contracts. This transaction generated a gain on sale of approximately $4.7 million and approximately $32.0 million in cash tax benefits.

4 - 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	$239.4	$218.1
Other Comprehensive Income (Loss)
Hedging	0.3	(0.8)

Total Other Comprehensive Income (Loss)	0.3	(0.8)

Total Comprehensive Income	$239.7	$217.3

Share-Based Compensation Plans: Effective January 1, 2006, we adopted 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 we 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. 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 and directors of $1.1 million ($0.01 per share) and $3.4 million ($0.03 per share) 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 $1.5 million and $3.7 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 and earnings per share 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, Except Per Share Amounts)
Net Income
As reported	$66.2	$218.1
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	0.5	1.3
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	1.0	2.4

Pro forma	$65.7	$217.0




Basic Earnings Per Common Share
As reported	$0.57	$1.86
Pro forma	$0.56	$1.85

Diluted Earnings Per Common Share
As reported	$0.56	$1.84
Pro forma	$0.55	$1.83

In the first nine months of 2006, the Compensation Committee of the Board of Directors (Compensation Committee) granted 1,304,275 options 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 1,328,966 options 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 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 our historical experience.

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

The exercise price of a 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 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.

The following is a summary of our stock option activity 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	8,537,331	$30.01	7,569,619	$28.10
Granted	12,000	$42.56	1,304,275	$39.50
Exercised	(214,405)	$24.01	(538,968)	$23.54
Forfeited	(21,908)	$36.86	(21,908)	$36.86

Outstanding at September 30, 2006	8,313,018	$30.16	8,313,018	$30.16

The aggregate intrinsic value of stock options exercised during the three and nine months ended September 30, 2006 was approximately $3.8 million and $9.4 million.

The following table summarizes information about stock options outstanding 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)

$10.86 to $19.97	301,443	$18.57	3.1	301,443	$18.57	3.1
$20.39 to $23.05	1,384,043	$22.00	4.9	1,384,043	$22.00	4.9
$25.31 to $27.65	1,764,994	$25.69	5.7	1,756,109	$25.70	5.7
$29.13 to $42.56	4,862,538	$34.83	7.8	2,259,721	$32.51	6.7

	8,313,018	$30.16	6.7	5,701,316	$27.12	5.8




Aggregate Intrinsic Value (Millions)	Options Outstanding			Options Exercisable

September 30, 2006	$107.9			$91.3

The following table summarizes the status of our non-vested options for the three and nine months ended September 30:

	Three Months		Nine Months

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


Non-vested - Beginning of Period	2,621,610	$7.94	1,360,153	$8.30
Granted	12,000	$7.69	1,304,275	$7.55
Vested	-	-	(30,818)	$7.18
Forfeited	(21,908)	$7.93	(21,908)	$7.93

Non-vested at September 30, 2006	2,611,702	$7.94	2,611,702	$7.94

The total fair value of options vesting during the three and nine months ended September 30, 2006 was zero and $0.2 million. As of September 30, 2006, total compensation cost related to non-vested stock

options not yet recognized was approximately $11.0 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity 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	202,341		193,657
Granted	-	$ -	18,152	$39.97
Released / Forfeited	(1,923)	$29.13	(11,391)	$30.94

Outstanding at September 30, 2006	200,418		200,418

Recipients of the 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.

We record the market value of the restricted stock awards on the date of grant and then we charge their value to 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 $0.2 million and $0.5 million for the three and nine months ended September 30, 2006. The impact was less than $0.01 per share for both the three and nine months ended September 30, 2006. Tax benefits realized for our restricted stock awards were zero and $0.2 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 $2.9 million, which is expected to be recognized over the next 54 months on a weighted-average basis.

In January 2004, the Compensation Committee granted 159,159 performance shares to officers and other key employees. In January 2006 and 2005 the Compensation Committee granted 150,281 and 101,834 performance units to 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 our 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. During the third quarter of 2006, we transferred $6.3 million from Common Equity to Other Liabilities to reflect participant elections to take cash under this amendment. 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 $1.1 million ($0.01 per share) and $2.7 million ($0.02 per share) for the three and nine months ended September 30, 2006. We have not realized any tax benefits associated with our performance awards 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 $7.2 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

Common Stock Activity: No new shares of common stock were issued during the nine months ended September 30, 2006. During the first nine months of 2006, we received proceeds of $12.5 million related to the exercise of stock options, compared with $44.1 million during the same period in 2005. We instructed our plan agent to purchase common stock in the open market at a cost of $21.8 million to fulfill the exercised stock options in the first nine months of 2006, compared with $70.3 million during the same period in 2005. This cost is included in purchase of common stock on our Consolidated Condensed Statements of Cash Flows.

Restrictions: Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from our principal utility subsidiaries, Wisconsin Electric and Wisconsin Gas. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our principal utility subsidiaries to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy.

As of December 31, 2005, the restricted net assets of consolidated and unconsolidated subsidiaries and our equity in undistributed earnings of 50 percent or less owned investees accounted for by the equity method total approximately $2.4 billion. This amount exceeds 25 percent of our consolidated net assets as of December 31, 2005.

See Note L - Short-Term Debt in our 2005 Annual Report on Form 10-K for discussion of certain financial covenants related to the bank back-up credit agreements of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas.

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

5 - 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 $368.4 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	$368.4	$355.5	$762.2
Pro forma	$368.4	$355.5	$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 - Asset Retirement Obligations and Note I - Nuclear Operations in our 2005 Annual Report on Form 10-K.

6 - 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 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 $53.6 million in regulatory assets related to derivatives in comparison to $4.8 million at December 31, 2005.

7 - 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	$8.4	$8.2	$3.1	$3.5
Interest cost	17.3	16.9	4.4	5.5
Expected return on plan assets	(20.2)	(21.6)	(3.7)	(3.9)
Amortization of:
Transition obligation	-	(0.1)	0.1	0.3
Prior service cost (credit)	1.4	1.2	(3.3)	0.2
Actuarial loss	5.9	5.3	2.2	1.7

Net Periodic Benefit Cost	$12.8	$9.9	$2.8	$7.3




Nine Months Ended September 30
Net Periodic Benefit Cost
Service cost	$25.4	$24.8	$9.3	$10.4
Interest cost	52.2	51.7	13.4	16.5
Expected return on plan assets	(61.2)	(65.4)	(11.2)	(11.6)
Amortization of:
Transition obligation	-	(0.1)	0.3	1.1
Prior service cost (credit)	4.1	3.8	(10.1)	0.5
Actuarial loss	17.6	15.7	6.6	5.3

Net Periodic Benefit Cost	$38.1	$30.5	$8.3	$22.2

In September 2006, we contributed $55.4 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.

8 - GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties on behalf of affiliates. 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)

Wisconsin Energy
Non-Utility Energy	$ -	$ -	$ -
Other	7.0	7.0	-

Wisconsin Electric	235.2	0.1	-
Subsidiary	10.8	10.5	-

Total	$253.0	$17.6	$ -

A Non-Utility Energy segment guarantee in support of Wisvest-Connecticut, which we sold in December 2002 to PSEG, provides financial assurance for potential obligations relating to environmental remediation under the original purchase agreement for Wisvest-Connecticut with United Illuminating. The potential obligations for environmental remediation, which are unlimited, are reimbursable by PSEG under the terms of the sale agreement in the event that we are required to perform under the guarantee.

Other guarantees support obligations of our affiliates to third parties under loan agreements and surety bonds. In the event our affiliates fail to perform, we would be responsible for the obligations.

Wisconsin Electric guarantees the potential retrospective premiums that could be assessed under Wisconsin Electric's nuclear insurance program.

Subsidiary guarantees support loan obligations and surety bonds between our affiliates and third parties. In the event our affiliates fail to perform, our subsidiary would be responsible for the obligations.

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 $21.0 million as of September 30, 2006 and $17.3 million as of December 31, 2005.

9 - 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		Corporate & Other (a) & Reconciling Items	Total Consolidated
Wisconsin Energy Corporation	Utility	Non-Utility	Corporate & Other (a) & Reconciling Items	Total Consolidated

	(Millions of Dollars)
Three Months Ended

September 30, 2006
Operating Revenues (b)	$835.7	$20.6	($16.5)	$839.8
Operating Income (Loss)	$121.6	$12.9	($3.3)	$131.2
Interest Expense	$25.6	$3.6	$12.3	$41.5
Income Tax Expense	$46.4	$4.0	($6.6)	$43.8
Net Income (Loss)	$72.7	$6.5	($8.4)	$70.8
Capital Expenditures	$104.0	$139.0	$0.1	$243.1

September 30, 2005
Operating Revenues (b)	$792.1	$19.5	($14.3)	$797.3
Operating Income (Loss)	$119.2	$11.5	($2.3)	$128.4
Interest Expense	$24.5	$4.0	$16.1	$44.6
Income Tax Expense	$43.9	$2.9	($6.8)	$40.0
Income from Discontinued Operations, Net	$ -	$ -	$0.4	$0.4
Net Income (Loss)	$69.3	$4.6	($7.7)	$66.2
Capital Expenditures	$98.9	$83.3	($0.9)	$181.3

Nine Months Ended

September 30, 2006
Operating Revenues (b)	$2,895.2	$55.0	($49.0)	$2,901.2
Operating Income (Loss)	$405.7	$33.5	($9.3)	$429.9
Interest Expense	$80.2	$11.5	$37.6	$129.3
Income Tax Expense	$149.4	$9.8	($20.0)	$139.2
Income from Discontinued Operations, Net	$ -	$ -	$4.5	$4.5
Net Income (Loss)	$241.9	$13.7	($16.2)	$239.4
Capital Expenditures	$317.1	$346.8	$0.1	$664.0
Total Assets (c)	$9,538.9	$1,130.1	($44.8)	$10,624.2

September 30, 2005
Operating Revenues (b)	$2,671.1	$25.0	($15.6)	$2,680.5
Operating Income (Loss)	$379.9	$10.8	($5.6)	$385.1
Interest Expense	$79.7	$10.0	$38.8	$128.5
Income Tax Expense	$133.3	$1.0	($34.0)	$100.3
Income from Discontinued Operations, Net	$ -	$5.0	$0.5	$5.5
Net Income (Loss)	$215.6	$5.9	($3.4)	$218.1
Capital Expenditures	$307.3	$191.4	$4.4	$503.1
Total Assets (c)	$9,132.4	$704.6	$163.1	$10,000.1

(a)	Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark, non-utility investment in renewable energy and recycling technology by Minergy Corp., the elimination of the PWGS 1 capital lease and the settlement of liabilities related to discontinued operations, as well as interest on corporate debt.

(b)	An elimination for intersegment revenues is included in Operating Revenues of $16.7 million and $15.5 million for the three months ended September 30, 2006 and 2005, respectively, and in the amounts of $49.8 million and $21.3 million for the nine months ended September 30, 2006 and 2005, respectively.

(c)	Effective July 2005, an elimination for intersegment assets is included in Other for the elimination of property under capital lease for PWGS 1. Wisconsin Electric leases PWGS 1 from We Power. For further information see Note 2.

10 - 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	11.4	6.1
Other, net	5.0	5.4	14.7	10.2

Total Other Income and Deductions	$15.2	$13.2	$44.8	$30.4

11 - 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.

WICOR Manufacturing: Effective July 31, 2004, we sold our manufacturing business. Pursuant to the terms of the sale agreement, Wisconsin Energy agreed to customary indemnification provisions related to certain environmental, asbestos and product liability matters associated with the manufacturing business. In addition, the amount of cash taxes and future deferred income tax benefits are subject to a number of factors including appraisals and applicable tax laws. We have established reserves related to the indemnification and tax matters.

Wisvest - Calumet: Pursuant to the terms of the sale agreement, Wisvest has agreed to customary indemnification provisions related to environmental conditions and other matters. Except for retention of the full exposure to indemnify Tenaska for environmental claims related to certain property that was no longer leased or owned by Wisvest or any of its subsidiaries at the time of sale, Wisvest's maximum aggregate exposure under the indemnification provisions is $35 million. Pursuant to the terms of the agreement, we have guaranteed post-closing obligations under the agreement, including indemnity obligations.

Minergy Neenah: In September 2006, we sold 100% of the membership interests in Minergy Neenah to Fox Valley Energy Holdings, LLC, an affiliate of Thermagen Power Group, LLC. For additional information regarding indemnification obligations, see Note 3 - Discontinued Operations.

12 - INCOME TAXES

As disclosed in Note H - Income Taxes in our 2005 Annual Report on Form 10-K, we had established valuation allowances related to tax benefits associated with state net operating losses. As of December 31, 2004, we had concluded that it was more likely than not that we would not ultimately

realize these tax benefits. In connection with the favorable decision by the Supreme Court of Wisconsin in June 2005 to uphold the Certificate of Public Convenience and Necessity (CPCN) granted by the PSCW for the construction of the Oak Creek expansion, we concluded that it was more likely than not that we will be able to utilize certain tax benefits associated with state net operating losses of the Parent that had been carried forward from prior years. Consequently, in the second quarter of 2005 we reversed $16.6 million of valuation allowances associated with the state tax net operating losses that have been carried forward to future years.

13 - 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 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
CONSOLIDATED EARNINGS

The following table compares our net income during the third quarter of 2006 with similar information during the third quarter of 2005 including favorable (better (B)) or unfavorable (worse (W)) variances.

	Three Months Ended September 30

	2006	B (W)	2005

	(Millions of Dollars)

Utility Energy Segment	$121.6	$2.4	$119.2
Non-Utility Energy Segment	12.9	1.4	11.5
Corporate and Other	(3.3)	(1.0)	(2.3)

Total Operating Income	131.2	2.8	128.4
Equity in Earnings of Transmission Affiliate	9.7	0.9	8.8
Other Income, Net	15.2	2.0	13.2
Interest Expense	41.5	3.1	44.6

Income From Continuing Operations Before Income Taxes	114.6	8.8	105.8
Income Taxes	43.8	(3.8)	40.0

Income From Continuing Operations	70.8	5.0	65.8
Income From Discontinued Operations, Net of Tax	-	(0.4)	0.4

Net Income	$70.8	$4.6	$66.2



Diluted Earnings Per Share
Continuing Operations	$0.60	$0.04	$0.56
Discontinued Operations	$ -	$ -	$ -

Total Diluted Earnings Per Share	$0.60	$0.04	$0.56

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our utility energy segment contributed $121.6 million of operating income during the third quarter of 2006, an increase of $2.4 million or 2.0% compared with the third quarter of 2005. The following table summarizes the operating income of this segment between the comparative quarters.

	Three Months Ended September 30

Utility Energy Segment	2006	B (W)	2005

	(Millions of Dollars)
Operating Revenues
Electric	$689.1	$26.6	$662.5
Gas	141.2	15.5	125.7
Other	5.3	1.4	3.9

Total Operating Revenues	835.6	43.5	792.1
Fuel and Purchased Power	230.8	10.7	241.5
Cost of Gas Sold	85.1	(4.8)	80.3

Gross Margin	519.7	49.4	470.3
Other Operating Expenses
Other Operation and Maintenance	294.9	(47.2)	247.7
Depreciation, Decommissioning
and Amortization	78.9	2.8	81.7
Property and Revenue Taxes	24.3	(2.6)	21.7

Operating Income	$121.6	$2.4	$119.2

Electric Utility Revenues and Sales

The following table compares 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.

	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	$246.2	$13.6	$232.6	2,340.2	(39.9)	2,380.1
Small Commercial/Industrial	221.8	11.5	210.3	2,506.9	(45.6)	2,552.5
Large Commercial/Industrial	170.7	(2.2)	172.9	2,926.9	(236.3)	3,163.2
Other-Retail/Municipal	25.8	(5.9)	31.7	556.0	(138.9)	694.9
Resale-Utilities	13.5	2.1	11.4	192.2	42.4	149.8
Other Operating Revenues	11.1	7.5	3.6	-	-	-

Total	$689.1	$26.6	$662.5	8,522.2	(418.3)	8,940.5




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.

Our electric utility operating revenues increased by $26.6 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 our PTF 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 4.7% 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 4.9% 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 20.0% 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 $10.7 million, or approximately 4.4%, when compared to the third quarter of 2005. The decrease is primarily due to the 4.7% reduction in megawatt-hour sales. Our cost of fuel and purchased power increased from $27.01 per megawatt-hour for the three months ended September 30, 2005 to $27.09 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 8.7% 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 $10.7 million or 23.6%.

	Three Months Ended September 30

	2006	B (W)	2005

	(Millions of Dollars)

Gas Operating Revenues	$141.2	$15.5	$125.7
Cost of Gas Sold	85.1	(4.8)	80.3

Gross Margin	$56.1	$10.7	$45.4

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	$33.5	$7.2	$26.3	50.6	6.3	44.3
Commercial/Industrial	9.9	2.0	7.9	34.8	2.5	32.3
Interruptible	0.4	(0.1)	0.5	3.9	(1.9)	5.8

Total Retail Gas Sales	43.8	9.1	34.7	89.3	6.9	82.4
Transported Gas	11.1	1.4	9.7	200.8	(20.2)	221.0
Other	1.2	0.2	1.0	-	-	-

Total	$56.1	$10.7	$45.4	290.1	(13.3)	303.4



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 pricing increases that were granted by the PSCW and implemented in January 2006. The gas pricing increases were granted to recover higher operating costs, including bad debt expenses. Our gross margin increased between the comparative periods by approximately $9.3 million due to these pricing increases.

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 mild weather in the third quarter of 2006.

Other Operation and Maintenance Expenses

Our other operation and maintenance expenses increased by $47.2 million, or 19.1%, 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 higher PTF lease costs of $17.7 million, increased transmission expenses of $14.6 million and increased bad debt expenses of $2.7 million. Other operation and maintenance expenses increased approximately $2.7 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 $2.8 million or 3.4% 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.

NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

The most significant subsidiary in this segment is We Power. This segment includes the revenues billed to Wisconsin Electric for PWGS 1 and it also includes the depreciation expense related to PWGS 1.

Our non-utility energy segment contributed $12.9 million of operating income for the third quarter of 2006 compared to operating income of $11.5 million for the third quarter of 2005. The slight increase in operating income primarily reflects a full quarter of operating income from PWGS 1, which was placed in service in July 2005.

CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME

Corporate and other affiliates had an operating loss of $3.3 million in the third quarter of 2006 compared with an operating loss of $2.3 million in the same period in 2005. The increase in operating loss is attributable to lower operating earnings at Wispark.

CONSOLIDATED OTHER INCOME, NET

Other income, net increased by $2.0 million or 15.2% when compared to the third quarter of 2005. The change relates primarily to increased equity Allowance for Funds used During Construction (equity-AFUDC) of $1.6 million between the comparative periods.

CONSOLIDATED INTEREST EXPENSE

Interest expense decreased by $3.1 million in the three months ended September 30, 2006 when compared with the same period in 2005. Our gross interest costs increased by approximately $3.0 million primarily due to increased debt levels; however, our capitalized interest increased by $6.1 million due to higher CWIP balances.

CONSOLIDATED INCOME TAXES

For the third quarter of 2006, our effective tax rate applicable to continuing operations was 38.2% compared to 37.8% for the third quarter of 2005. We expect our 2006 annual effective tax rate to be slightly below 37.5%.

DISCONTINUED OPERATIONS

In the third quarter of 2006 we did not have income from discontinued operations. In the third quarter of 2005, income from discontinued operations was $0.4 million.

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

The following table compares our net income during the first nine months of 2006 with similar information during the first nine months of 2005 including favorable (better (B)) or unfavorable (worse (W)) variances.

	Nine Months Ended September 30

	2006	B (W)	2005

	(Millions of Dollars)

Utility Energy Segment	$405.7	$25.8	$379.9
Non-Utility Energy Segment	33.5	22.7	10.8
Corporate and Other	(9.3)	(3.7)	(5.6)

Total Operating Income	429.9	44.8	385.1
Equity in Earnings of Transmission Affiliate	28.7	2.8	25.9
Other Income, Net	44.8	14.4	30.4
Interest Expense	129.3	(0.8)	128.5

Income From Continuing Operations Before Income Taxes	374.1	61.2	312.9
Income Taxes	139.2	(38.9)	100.3

Income From Continuing Operations	234.9	22.3	212.6
Income From Discontinued Operations, Net of Tax	4.5	(1.0)	5.5

Net Income	$239.4	$21.3	$218.1



Diluted Earnings Per Share
Continuing Operations	$1.98	$0.18	$1.80
Discontinued Operations	$0.04	$ -	$0.04

Total Diluted Earnings Per Share	$2.02	$0.18	$1.84

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our utility energy segment contributed $405.7 million of operating income during the first nine months of 2006, an increase of $25.8 million or 6.8% compared with the first nine months of 2005. The following table summarizes the operating income of this segment between the comparative periods.

	Nine Months Ended September 30

Utility Energy Segment	2006	B (W)	2005

	(Millions of Dollars)
Operating Revenues
Electric	$1,901.0	$140.2	$1,760.8
Gas	973.1	81.5	891.6
Other	21.1	2.4	18.7

Total Operating Revenues	2,895.2	224.1	2,671.1
Fuel and Purchased Power	586.9	1.0	587.9
Cost of Gas Sold	695.1	(62.1)	633.0

Gross Margin	1,613.2	163.0	1,450.2
Other Operating Expenses
Other Operation and Maintenance	900.3	(137.9)	762.4
Depreciation, Decommissioning
and Amortization	234.0	6.8	240.8
Property and Revenue Taxes	73.2	(6.1)	67.1

Operating Income	$405.7	$25.8	$379.9

Electric Utility Revenues and Sales

The following table compares 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.

	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	$654.5	$33.1	$621.4	6,247.4	(232.2)	6,479.6
Small Commercial/Industrial	609.5	48.0	561.5	6,940.2	(40.9)	6,981.1
Large Commercial/Industrial	486.4	23.1	463.3	8,497.6	(378.6)	8,876.2
Other-Retail/Municipal	71.9	(12.0)	83.9	1,680.9	(361.8)	2,042.7
Resale-Utilities	49.4	33.5	15.9	988.9	733.9	255.0
Other Operating Revenues	29.3	14.5	14.8	-	-	-

Total	$1,901.0	$140.2	$1,760.8	24,355.0	(279.6)	24,634.6




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.

Our electric utility operating revenues increased by $140.2 million, or 8.0%, when compared to 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 our PTF 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 1.1% 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 2.6% 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 17.7% 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 $1.0 million, or approximately 0.2%, when compared to the first nine months of 2005. Our cost of fuel and purchased power increased from $23.87 per megawatt-hour for the nine months ended September 30, 2005 to $24.10 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 2.3% 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 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 $19.4 million or 7.5%.

	Nine Months Ended September 30

	2006	B (W)	2005

	(Millions of Dollars)

Gas Operating Revenues	$973.1	$81.5	$891.6
Cost of Gas Sold	695.1	(62.1)	633.0

Gross Margin	$278.0	$19.4	$258.6

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	$175.1	$9.1	$166.0	478.9	(51.7)	530.6
Commercial/Industrial	57.9	7.6	50.3	290.3	(19.9)	310.2
Interruptible	1.4	-	1.4	14.6	(2.5)	17.1

Total Retail Gas Sales	234.4	16.7	217.7	783.8	(74.1)	857.9
Transported Gas	37.7	2.2	35.5	630.5	(45.1)	675.6
Other	5.9	0.5	5.4	-	-	-

Total	$278.0	$19.4	$258.6	1,414.3	(119.2)	1,533.5



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 pricing increases that were granted by the PSCW and implemented in January 2006. The gas pricing increases were primarily granted to recover higher operating costs, including bad debt expenses. Our gross margin increased between the comparative periods by approximately $35.4 million due to these pricing increases. We anticipate that the 2006 annual impact of the rate increase on our gas margins would be approximately $53.5 million under normal customer usage; however, we believe that the actual amount may be lower due to reduced customer usage.

The pricing increases were 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 than 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 $13.5 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 mild weather in the first nine months of 2006.

Other Operation and Maintenance Expenses

Our other operation and maintenance expenses increased by $137.9 million, or 18.1%, 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 higher PTF lease costs of $68.2 million, increased transmission expenses of $45.2 million and increased bad debt expenses of $9.6 million. Other operation and maintenance expenses increased approximately $15.2 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 approximately a $10.6 million decrease 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 $6.8 million or 2.8% 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.

NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our non-utility energy segment contributed $33.5 million of operating income for the first nine months of 2006 compared to operating income of $10.8 million for the first nine months of 2005. This increase in operating income primarily reflects nine months of operating income in 2006 from PWGS 1, which was placed in service in July 2005. There were no earnings associated with this unit in the first six months of 2005.

CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME

Corporate and other affiliates had an operating loss of $9.3 million in the first nine months of 2006 compared with an operating loss of $5.6 million in the same period in 2005. The increase in operating loss is attributable to lower operating earnings at Wispark.

CONSOLIDATED OTHER INCOME, NET

Other income, net increased by $14.4 million when compared to the nine months ended September 30, 2005. The largest increases relate to increased equity-AFUDC and capitalized carrying costs of $9.9 million and the pre-tax gain on the sale of our investment in Guardian of $2.8 million. For further information on the sale of Guardian, see Other Matters in Factors Affecting Results, Liquidity and Capital Resources below.

CONSOLIDATED INTEREST EXPENSE

Interest expense increased by $0.8 million in the nine months ended September 30, 2006 when compared with the same period in 2005. Our gross interest costs increased by $5.7 million primarily due to increased debt levels; however our capitalized interest increased by $4.9 million due to higher CWIP balances. In addition, in the nine months ended September 30, 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.

CONSOLIDATED INCOME TAXES

For the first nine months of 2006, our effective tax rate applicable to continuing operations was 37.2% compared to 32.1% for the first nine months of 2005. The lower effective tax rate in 2005 was due to the June 2005 reversal of $16.6 million of valuation allowances associated with state tax net operating losses that have been carried forward. For additional information, see Note 12 - Income Taxes in the Notes to

Consolidated Condensed Financial Statements in this report. We expect our 2006 annual effective tax rate to be slightly below 37.5%.

DISCONTINUED OPERATIONS

Income from discontinued operations for the first nine months of 2006 was $4.5 million compared to $5.5 million in the first nine months of 2005. In the first nine months of 2006, we had income of approximately $2.8 million related to the favorable resolution of tax liabilities. Income from discontinued operations for the first nine months of 2005 includes an after tax gain on the sale of Calumet of $4.7 million. The operations of Calumet were sold effective May 31, 2005.

LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS

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

	Nine Months Ended September 30

Wisconsin Energy Corporation	2006	2005

	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$708.3	$564.0
Investing Activities	($650.3)	($471.3)
Financing Activities	($110.0)	($98.5)

Operating Activities

Cash provided by operating activities for the nine months ended September 30, 2006 totaled $708.3 million, which is a $144.3 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 $60.5 million. Partially offsetting these items was an increase of cash taxes of approximately $41.4 million due to higher taxable earnings.

Investing Activities

Cash used in investing activities for the nine months ended September 30, 2006 totaled $650.3 million, which is a $179.0 million increase over the same period last year. This increase is primarily associated with the increased capital expenditures related to our new generating plants. During 2006, we had capital expenditures related to the Oak Creek expansion and the second Port Washington natural gas-fired unit. During the first nine months of 2005, we had significantly lower capital expenditures related to these units.

Financing Activities

During the nine months ended September 30, 2006, we used $110.0 million for financing activities compared with using $98.5 million for financing activities during the first nine months of 2005. Wisconsin Energy retired at the scheduled maturity date $250.0 million of 5.875% Notes due April 1, 2006. Short-term debt was issued to retire these notes. During the first nine months of 2006, short-term debt increased approximately $253.0 million. In addition, in the first nine months of 2006 and 2005 we used cash to pay dividends on common stock.

In the first nine months of 2006, we received proceeds of $12.5 million related to the exercise of stock options, compared with $44.1 million in the first nine months of 2005. Instead of issuing new shares for these stock options, we instructed our plan agent to purchase common stock in the open market at a cost of $21.8 million in the first nine months of 2006, compared with $70.3 million for the same period of 2005. This cost is included in Purchase of common stock on our Consolidated Condensed Statements of Cash Flows.

CAPITAL RESOURCES AND REQUIREMENTS
Capital Resources

We anticipate meeting our capital requirements during the remaining three 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. 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.

Wisconsin Electric expects to retire at the scheduled maturity date, $200 million of 6-5/8% debentures due November 15, 2006. Wisconsin Electric anticipates 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.

Wisconsin Energy, Wisconsin Electric and Wisconsin Gas credit agreements provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes.

As of September 30, 2006, we had approximately $1.7 billion of available unused lines of bank back-up credit facilities on a consolidated basis and approximately $709.3 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 such facilities at September 30, 2006:

Company	Total Facility	Letters of Credit	Credit Available	Facility Expiration	Facility Term

	(Millions of Dollars)

Wisconsin Energy	$900.0	$1.6	$898.4	April 2011	5 year
Wisconsin Electric	$500.0	$2.1	$497.9	March 2011	5 year
Wisconsin Gas	$300.0	$ -	$300.0	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	$2,834.6	41.5%	$2,680.1	40.0%
Preferred Stock of Subsidiary	30.4	0.5%	30.4	0.5%
Long-Term Debt (including
current maturities)	3,253.0	47.6%	3,527.0	52.7%
Short-Term Debt	709.3	10.4%	456.3	6.8%

Total	$6,827.3	100.0%	$6,693.8	100.0%



Ratio of Debt to Total Capital		58.0%		59.5%

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 the debt securities and preferred stock of our subsidiaries 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

Wisconsin Energy
Commercial Paper	A-2	P-2	F2
Unsecured Senior Debt	BBB+	A3	A-

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

Wisconsin Gas
Commercial Paper	A-2	P-1	F1
Unsecured Senior Debt	A-	A1	A+

Wisconsin Energy Capital Corporation
Unsecured Debt	BBB+	A3	A-

On June 15, 2006, Fitch affirmed the security ratings of Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and Wisconsin Energy Capital Corporation and changed the security ratings outlook for Wisconsin Energy and Wisconsin Energy Capital Corporation from stable to negative. The security ratings outlooks assigned by Fitch for Wisconsin Electric and Wisconsin Gas are stable.

On June 8, 2006, S&P affirmed the security ratings and ratings outlook of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas. The security ratings outlooks assigned by S&P for Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and Wisconsin Energy Capital Corporation are negative.

The security ratings outlooks assigned by Moody's for Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and Wisconsin Energy Capital Corporation are 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 consolidated capital expenditure budget, excluding the purchase of nuclear fuel, is approximately $1.020 billion.

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 construction projects, 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 8 - 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 G - 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 decreased to approximately $9.4 billion as of September 30, 2006 compared with $9.6 billion as of December 31, 2005. This decrease was due primarily to the scheduled maturity of $250.0 million of Wisconsin Energy 5.875% Notes due April 1, 2006 and periodic payments made in the ordinary course of business during the nine months ended September 30, 2006. Purchase obligations under coal supply contracts, gas supply contracts and nuclear contracts for uranium, enrichment and fabrication partially offset these decreases.

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, our PTF 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 $70.2 million.

POWER THE FUTURE

Under our PTF strategy, we expect to meet a significant portion of our future generation needs through the construction of the PWGS and the Oak Creek expansion by We Power. The new plants will be leased by We Power to Wisconsin Electric under long-term leases, and we expect Wisconsin Electric to recover the lease payments in its 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 PTF.

The PTF units include PWGS Unit 1 and Unit 2 and Oak Creek expansion Unit 1 and Unit 2. The following table identifies certain key items related to the units:

Unit Name	Expected In Service	Authorized Cash Costs

PWGS 1	July 2005 (Actual)	$333.2 million (Actual)
PWGS 2	Summer 2008	$331 million
OC 1	Summer 2009	$1,300 million
OC 2	Summer 2010	$640 million

The lease payments are based on the cash costs authorized by our primary regulator. Under the lease terms, our return is calculated using a 12.7% return on equity and the equity ratio is assumed to be 53% for the PWGS Units and 55% for the OC Units. The return will reflect interest rates at the time the units are placed in service. The authorized cash costs for the Oak Creek expansion units represent our share (83% ownership interest) in the project.

Construction of the second gas-fired unit at PWGS is well underway. Site preparation, including removal of the old coal units at the site, was completed early this year, and all of the major components have been procured for the second unit at PWGS.

The 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, Wisconsin Electric received an order from the PSCW that allowed it to increase annual electric revenues by approximately $222.0 million to recover increased costs associated with investments in our PTF units, transmission services and fuel and purchased power, as well as costs associated with additional sources of renewable energy. The order also required Wisconsin Electric to refund to customers, with interest, any fuel revenues that it receives that are in excess of fuel and purchased power costs that it incurs, 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 for Wisconsin Electric operations under the January 2006 order is 11.2%.

For 2007, Wisconsin Electric expects 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: The gas operations of Wisconsin Electric and Wisconsin Gas 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 increases in gas revenues totaling $60.1 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, Wisconsin Electric 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, Wisconsin Electric and Wisconsin Gas 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, Wisconsin Electric 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 Wisconsin Electric's existing wholesale electric customers. We anticipate a decision by the end of the year.

See Factors Affecting Results, Liquidity and Capital Resources - Utility 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)

Wisconsin Energy and Wisconsin Electric were exempt holding companies 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, each of Wisconsin Energy and Wisconsin Electric filed with the FERC notification of its 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, Wisconsin Energy and Wisconsin Electric received notice from the FERC confirming their status as holding companies 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 our PTF 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

Wisconsin Electric owns 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 Wisconsin Electric 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 Wisconsin Electric. 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, Wisconsin Electric and Edison Sault 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, Wisconsin Electric along with certain other parties to the proceeding, submitted an offer of settlement to the presiding administrative law judge that resolved all issues set for hearing that impact Wisconsin Electric 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. Wisconsin Electric and Edison Sault were granted substantially all of the FTRs that they 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

Guardian Pipeline: In April 2006, Wisconsin Energy sold its one-third interest in Guardian to an affiliate of Northern Border Partners, L.P. for approximately $38.5 million. The sale generated an after-tax gain of approximately $1.7 million. Guardian owns an interstate natural gas pipeline from the Joliet, Illinois market hub to southeastern Wisconsin that is designed to serve the growing demand for natural gas in Wisconsin and northern Illinois. Guardian pipeline began commercial operation in early December 2002. We have committed to purchase 650,000 dekatherms (approximately 87% of the pipeline's total capacity) per day of capacity on the pipeline over a long-term contract that expires in December 2012.

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 13 - 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 Energy. 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 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 our 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.

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Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances.

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, us or any of our subsidiaries; 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 Wisconsin Electric 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.

Possible risks associated with non-utility operations and investments, such as: general economic conditions; competition; operating risks; dependence upon certain suppliers and customers; the cyclical nature of property values that could affect real estate investments; unanticipated changes in environmental or energy regulations; and risks associated with minority investments, where there is a limited ability to control the development, management or operation of the project.

Legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the State of Wisconsin's amended public utility holding company law.

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 Energy Corporation, 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 Energy'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 Energy'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 (the 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 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 Wisconsin Electric, Wisconsin Gas and Edison Sault 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 our PTF strategy.

OTHER MATTERS

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

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

In May 2005, a stray voltage lawsuit was filed against Wisconsin Electric. 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 Wisconsin Electric 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 Wisconsin Electric with respect to stray voltage and ground currents are not expected to have a material adverse effect on its 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: Wisconsin Electric and Wisconsin Gas 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 Wisconsin Electric

owned a parcel of property that is within the property boundaries of the site. A predecessor company of Wisconsin Gas had a customer and corporate relationship with the entity that owned and operated the site, Milwaukee Solvay Coke Company. In July 2005, Wisconsin Gas received a general notice letter from the EPA identifying Wisconsin Gas as a potentially responsible party under CERCLA. We responded to the EPA in July 2005, stating that Wisconsin Gas will participate in negotiations regarding the site, but that Wisconsin Gas does not admit to any liability for the site. In April 2006, we received a special notice letter from the EPA identifying both Wisconsin Gas and Wisconsin Electric as potentially responsible parties 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. Wisconsin Electric and Wisconsin Gas, 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 Wisconsin Electric and Wisconsin Gas are negotiating to perform the RI/FS pursuant to an administrative order on consent with the EPA, neither company admits to any liability for the site, waives any liability defenses, or commits 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 S - 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. Wisconsin Electric and Edison Sault were granted substantially all of the FTRs that they 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 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS [AND ISSUER PURCHASES OF EQUITY SECURITIES]

ISSUER PURCHASES OF EQUITY SECURITIES

There were no purchases of our equity securities made by or on behalf of us or any affiliated purchaser (as defined in Exchange Act Rule 10b-18) during the three month period ended September 30, 2006. We do not report shares purchased by independent agents to satisfy obligations under our employee benefit plans and stock purchase and dividend reinvestment plan under this Item.

ITEM 6. EXHIBITS

Exhibit No.


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 ENERGY CORPORATION
	(Registrant)

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