AND RESULTS OF OPERATIONS

INTRODUCTION

Wisconsin Energy Corporation is a diversified holding company with subsidiaries primarily in 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 utility energy segment primarily consists of Wisconsin Electric and Wisconsin Gas, both doing business under the trade name of "We Energies." We generate and distribute electricity in Wisconsin and the Upper Peninsula of Michigan and we distribute natural gas in Wisconsin. Our non-utility energy segment primarily consists of We Power. We Power is principally engaged in the engineering, construction and development of electric power generating facilities for long-term lease to Wisconsin Electric under our PTF strategy.

CORPORATE STRATEGY

Business Opportunities

We have three primary investment opportunities and earnings streams: our regulated utility business; our investment in ATC; and our generation plants within our non-utility energy segment.

Our regulated utility business primarily consists of electric generation assets and the electric and gas distribution assets that serve the electric and gas customers of Wisconsin Electric and Wisconsin Gas. During 2012, our regulated utility earned $647.7 million of operating income. Over the next three years, we expect to invest approximately $2.0 billion in this business to construct renewable generation, to convert the fuel source for VAPP from coal to natural gas, to update the electric and gas distribution infrastructure, and for other utility projects.

We have a $378.3 million investment in ATC, which represents a 26.2% ownership interest. Our 2012 pre-tax earnings from ATC totaled $65.7 million and we received $52.6 million in dividends from ATC. Over the next three years, we expect to make capital contributions of approximately $40 million in ATC as it continues to invest in transmission projects. During the same period, we expect to invest $47 million in ATC through undistributed earnings.

Our non-utility energy segment consists primarily of the four generation plants constructed as part of our PTF strategy. All four plants have been placed in service and are being leased to Wisconsin Electric under long-term leases that run for 25 years (PWGS 1 and PWGS 2) and 30 years (OC 1 and OC 2). We recognize revenues on a levelized basis over the life of the lease. During 2013, we expect this segment's operating income to be between $360 million and $365 million. The PTF strategy was developed with the primary goal of constructing these power plants. Over the next three years, we do, however, expect to invest approximately $97 million in this segment on smaller capital projects, including the Oak Creek expansion fuel flexibility project. For additional information on this project, see Factors Affecting Results, Liquidity and Capital Resources -- Other Matters.

CONSOLIDATED EARNINGS

The following table compares our operating income by business segment and our
net income for 2012, 2011 and 2010:

            Wisconsin Energy Corporation                   2012        2011        2010
                                                              (Millions of Dollars)

Utility Energy                                          $  647.7     $ 544.8     $ 564.0
Non-Utility Energy                                         358.8       348.9       252.4
Corporate and Other                                         (6.2 )      (6.4 )      (6.0 )
Total Operating Income                                   1,000.3       887.3       810.4
Equity in Earnings of Transmission Affiliate                65.7        62.5        60.1
Other Income and Deductions, net                            34.8        62.7        40.2
Interest Expense, net                                      248.2       235.8       206.4
Income from Continuing Operations Before Income Taxes      852.6       776.7       704.3
Income Tax Expense                                         306.3       263.9       249.9
Income from Continuing Operations                          546.3       512.8       454.4
Income from Discontinued Operations, Net of Tax                -        13.4         2.1
Net Income                                              $  546.3     $ 526.2     $ 456.5

Diluted Earnings Per Share
Continuing Operations                                   $   2.35     $  2.18     $  1.92
Discontinued Operations                                        -        0.06        0.01
Total Diluted Earnings Per Share                        $   2.35     $  2.24     $  1.93

An analysis of contributions to operating income by segment and a more detailed analysis of results follows.

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

The following table summarizes our utility energy segment's operating income
during 2012, 2011 and 2010:

    Utility Energy Segment           2012         2011         2010
                                         (Millions of Dollars)
Operating Revenues
Electric                          $ 3,193.9    $ 3,211.3    $ 2,936.3
Gas                                   962.6      1,181.2      1,190.2
Other                                  34.3         39.0         38.8
Total Operating Revenues            4,190.8      4,431.5      4,165.3
Operating Expenses
Fuel and Purchased Power            1,103.8      1,174.5      1,104.7
Cost of Gas Sold                      545.8        728.7        751.5
Other Operation and Maintenance     1,476.5      1,613.4      1,587.0
Depreciation and Amortization         296.4        257.0        251.4
Property and Revenue Taxes            120.6        113.1        105.1
Total Operating Expenses            3,543.1      3,886.7      3,799.7
Amortization of Gain                      -            -        198.4
Operating Income                  $   647.7    $   544.8    $   564.0

2012 vs. 2011: Our utility energy segment contributed $647.7 million of operating income during 2012 compared with $544.8 million of operating income during 2011. The increase in operating income was primarily caused by decreased other operation and maintenance expense and decreased fuel and purchased power expenses.

2011 vs. 2010: Our utility energy segment contributed $544.8 million of operating income during 2011 compared with $564.0 million of operating income during 2010. The decrease in operating income was primarily caused by increased other operation and maintenance expense and unfavorable weather during 2011 as compared to 2010, partially offset by wholesale electric pricing increases and electric sales growth.

Electric Utility Gross Margin

The following table compares our electric utility gross margin during 2012 with
similar information for 2011 and 2010, including a summary of electric operating
revenues and electric sales by customer class:

                                     Electric Revenues and Gross Margin                     MWh Sales
 Electric Utility Operations          2012            2011          2010          2012         2011         2010
                                            (Millions of Dollars)                          (Thousands)
Customer Class
Residential                      $     1,163.9     $ 1,159.2     $ 1,114.3      8,317.7      8,278.5      8,426.3
Small Commercial/Industrial            1,013.6       1,006.9         922.2      8,860.0      8,795.8      8,823.3
Large Commercial/Industrial              744.3         763.7         677.1      9,710.7      9,992.2      9,961.5
Other - Retail                            22.8          22.9          21.9        154.8        153.6        155.3
Total Retail                           2,944.6       2,952.7       2,735.5     27,043.2     27,220.1     27,366.4
Wholesale - Other                        144.4         154.0         134.6      1,566.6      2,024.8      2,004.6
Resale - Utilities                        53.4          69.5          40.4      1,642.4      2,065.7      1,103.8
Other Operating Revenues                  51.5          35.1          25.8            -            -            -
Total                                  3,193.9       3,211.3       2,936.3     30,252.2     31,310.6     30,474.8

Fuel and Purchased Power
Fuel                                     541.6         644.4         570.5
Purchased Power                          548.7         514.8         521.0
Total Fuel and Purchased Power         1,090.3       1,159.2       1,091.5
Total Electric Gross Margin      $     2,103.6     $ 2,052.1     $ 1,844.8

Weather - Degree Days (a)
Heating (6,662 Normal)                                                            5,704        6,633        6,183
Cooling (696 Normal)                                                              1,041          793          944

(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.

Electric Utility Revenues and Sales

2012 vs. 2011: Our electric utility operating revenues decreased by $17.4 million, or 0.5%, when compared to 2011. The most significant factors that caused a change in revenues were:

• Favorable weather as compared to the prior year that increased electric revenues by an estimated $28.5 million.

• Other operating revenues increased by approximately $16.4 million, driven by the $25.9 million amortization of a settlement with the DOE. For additional information on the DOE settlement, see Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations.

• A planned outage at an iron ore mine of our largest customer and the conversion to self-generation of two other large customers decreased electric revenues by an estimated $20.4 million.

• A $16.2 million reduction in sales for resale due to reduced sales into the MISO Energy Markets.

• Lower MWh sales to our wholesale customers, which decreased revenue by an estimated $12.4 million as compared to 2011.

As measured by cooling degree days, 2012 was 49.6% warmer than normal, and 31.3% warmer than 2011. We believe the warmer summer weather was the primary reason for the 0.5% increase in residential sales and the 0.7% increase in small commercial/industrial sales. The increase due to warmer summer weather was partially offset by reduced sales from warmer winter weather in the first quarter of 2012 as compared to the first quarter of 2011.

Sales to our large commercial/industrial customers decreased by 2.8% primarily due to the planned outage at an iron ore mine of our largest customer and the conversion to self-generation of two other large customers. Excluding sales to these three customers, MWh sales to large commercial/industrial customers increased by 1.1%. Wholesale sales decreased primarily due to the low market price of power in 2012 as compared to 2011, which caused some of these customers to obtain energy from the MISO market rather than through our contracts. The reduction did not impact the majority of revenue received from these customers, which is tied to demand. The lower market price of power also reduced our ability to sell energy into the MISO Energy Markets.

2011 vs. 2010: Our electric utility operating revenues increased by $275.0 million, or 9.4%, when compared to 2010. The most significant factors that caused a change in revenues were:

• 2011 increase of approximately $198.4 million, reflecting the reduction of Point Beach bill credits to retail customers. For information on the bill credits, see Amortization of Gain below.

• Net pricing increases totaling $48.8 million, which includes rates related to our 2010 fuel recovery request that became effective March 25, 2010, and our request to review 2011 fuel costs that became effective April 29, 2011. For information on these rate orders, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters.

• Unfavorable weather as compared to 2010 that decreased electric revenues by an estimated $40.5 million.

• A $20.4 million increase in revenue from energy sold into the MISO Energy Markets, which was driven by increased MWh generation from our Oak Creek expansion units.

• Net economic growth that increased electric revenues by an estimated $16.2 million as compared to 2010.

• Higher MWh sales to our wholesale customers, which increased revenue by an estimated $10.4 million as compared to 2010.

As measured by cooling degree days, 2011 was 11.8% warmer than normal, but 16.0% cooler than 2010. The 1.8% decrease in residential sales volumes in 2011 is primarily attributable to weather. The estimated 1.8% impact of cooler summer weather on our small commercial/industrial sales volumes was almost entirely offset by an estimated 1.5% increase in sales due to modest economic growth. Increased sales to our largest customers, two iron ore mines, accounted for the increase in sales to our large commercial/industrial customers. If these sales are excluded, sales to our large commercial/industrial customers decreased by approximately 1.2% for 2011 as compared to 2010 primarily because of previously announced plant closings.

Electric Fuel and Purchased Power Expenses

2012 vs. 2011: Our electric fuel and purchased power costs decreased by $68.9 million, or approximately 5.9%, when compared to 2011. This decrease was primarily caused by a 3.4% decrease in total MWh sales as well as a reduction in our average cost of fuel and purchased power because of lower natural gas prices.

2011 vs. 2010: Our electric fuel and purchased power costs increased by $67.7 million, or approximately 6.2%, when compared to 2010. This increase was primarily caused by a 2.7% increase in total MWh sales as well as increased coal and related transportation costs, partially offset by lower natural gas prices.

Gas Utility Revenues, Gross Margin and Therm Deliveries

The following table compares our total gas utility operating revenues and gross margin (total gas utility operating revenues less cost of gas sold) during 2012, 2011 and 2010. Operating revenues and cost of gas sold has declined over the last three years due to the decline in the commodity cost of natural gas during this three year period.

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ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL          2012 Form 10-K
         CONDITION AND RESULTS OF OPERATIONS - (Cont'd)



Gas Utility Operations     2012        2011         2010
                               (Millions of Dollars)

Operating Revenues       $ 962.6    $ 1,181.2    $ 1,190.2
Cost of Gas Sold           545.8        728.7        751.5
Gross Margin             $ 416.8    $   452.5    $   438.7

We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under GCRMs. The following table compares our gas utility gross margin and therm deliveries by customer class during 2012, 2011 and 2010:

                                     Gross Margin                    Therm Deliveries
 Gas Utility Operations       2012        2011       2010       2012       2011       2010
                                 (Millions of Dollars)                  (Millions)
Customer Class
Residential                 $  267.9    $ 290.2    $ 282.2      676.4      776.8      741.2
Commercial/Industrial           88.8      101.5       95.8      390.6      461.7      429.6
Interruptible                    1.7        1.8        2.2       14.6       16.0       19.4
Total Retail                   358.4      393.5      380.2    1,081.6    1,254.5    1,190.2
Transported Gas                 52.9       52.6       51.3    1,140.4      899.6      914.9
Other Operating                  5.5        6.4        7.2          -          -          -
Total                       $  416.8    $ 452.5    $ 438.7    2,222.0    2,154.1    2,105.1

Weather - Degree Days (a)
Heating (6,662 Normal)                                          5,704      6,633      6,183

(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.

2012 vs. 2011: Our total retail gas margin decreased by $35.1 million, or approximately 8.9%, when compared to 2011 primarily because of a decrease in sales volumes as a result of warmer winter weather. As measured by heating degree days, 2012 was 14.0% warmer than 2011 and 14.4% warmer than normal.

Transported gas volumes increased by 26.8% when compared to 2011. Virtually all of the volume increase related to gas used in electric generation, which has a small impact on margin.

2011 vs. 2010: Our gas margin increased by $13.8 million, or approximately 3.1%, when compared to 2010 primarily because of an increase in sales volumes as a result of colder winter weather in 2011 as compared to 2010. As measured by heating degree days, 2011 was 7.3% colder than 2010 and 0.3% colder than normal.

Other Operation and Maintenance Expense

2012 vs. 2011: Our other operation and maintenance expense decreased by $136.9 million, or approximately 8.5%, when compared to 2011. This decrease is primarily due to the one year suspension of $148 million of amortization expense on certain regulatory assets as authorized under our 2012 Wisconsin Rate Case. For additional information on the 2012 rate case, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters.

Our utility operation and maintenance expenses are influenced by, among other things, labor costs, employee benefit costs, plant outages and amortization of regulatory assets. We expect our 2013 other operation and maintenance expense to stay fairly flat because we anticipate that the 2013 Wisconsin Rate Case reinstatement of amortization on certain regulatory assets will be offset by an extension of the recovery period for certain regulatory assets and a significant reduction of escrowed bad debt expense.

2011 vs. 2010: Our other operation and maintenance expense increased by $26.4 million, or approximately 1.7%, when compared to 2010. Higher maintenance costs at one of our natural gas peaking plants, increased spending on forestry work for our electric distribution system and increased costs associated with the amortization of deferred PTF costs related to wholesale and Michigan customers were the primary drivers of the increase.

Depreciation and Amortization Expense

2012 vs. 2011: Depreciation and Amortization expense increased by $39.4 million, or approximately 15.3%, when compared to 2011. This increase was primarily because of an overall increase in utility plant in service. The Glacier Hills Wind Park went into service in December 2011. In addition, the emission control equipment for units 5 and 6 of the Oak Creek AQCS project went into service in March 2012, and for units 7 and 8 in September 2012. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters -- Oak Creek Air Quality Control System.

We expect depreciation and amortization expense to increase in 2013 primarily as a result of an increase in utility plant in service related to the Oak Creek AQCS project, which will have been in service a full year.

2011 vs. 2010: Depreciation and Amortization expense increased by $5.6 million, or approximately 2.2%, when compared to 2010. This increase was primarily because of an overall increase in utility plant in service.

Amortization of Gain

In connection with the September 2007 sale of Point Beach, we reached an agreement with our regulators to allow for the net gain on the sale to be used for the benefit of our customers. The majority of the benefits were returned to customers in the form of bill credits. The net gain was originally recorded as a regulatory liability, and it was amortized to the income statement as we issued bill credits to customers. When the bill credits were issued to customers, we transferred cash from the restricted accounts to the unrestricted accounts, adjusted for taxes. All bill credits associated with the sale of Point Beach were applied to customers as of December 31, 2010, and as a result, the Amortization of Gain was zero during 2012 and 2011 as compared to $198.4 million during 2010.

NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our non-utility energy segment consists primarily of our PTF units (PWGS 1, PWGS 2, OC 1 and OC 2). PWGS 1 and PWGS 2 were placed in service in July 2005 and May 2008, respectively. The common facilities associated with the Oak Creek expansion include the water intake system, which was placed in service in January 2009, the coal handling system, which was placed in service in November 2007, and other smaller assets. OC 1 and OC 2 were placed in service in February 2010 and January 2011, respectively.

The table below reflects:

• A full year's earnings for 2012, 2011 and 2010 for:

? PWGS 1;

? PWGS 2;

? the coal handling system for the Oak Creek expansion; and

? the water intake system for the Oak Creek expansion.

• A full year's earnings for 2012 and 2011 and approximately eleven months of earnings for 2010 for OC 1; and

• A full year's earnings for 2012 and approximately eleven and a half months of earnings for 2011 for OC 2.

This segment reflects the lease revenues on the new units as well as the depreciation expense. Operating and maintenance costs and limited management fees associated with the plants are the responsibility of Wisconsin Electric and are recorded in the utility segment.

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ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL          2012 Form 10-K
         CONDITION AND RESULTS OF OPERATIONS - (Cont'd)



                                    2012        2011       2010
                                       (Millions of Dollars)

Operating Revenues                $  439.9    $ 435.1    $ 320.2
Operation and Maintenance Expense     14.0       13.7       14.3
Depreciation Expense                  67.1       72.5       53.5
Operating Income (Loss)           $  358.8    $ 348.9    $ 252.4

Non-utility energy segment operating income increased $9.9 million, or approximately 2.8%, primarily because of a decrease in depreciation expense related to finalized depreciable lives of the Oak Creek expansion units and a full year's earnings in 2012 for OC 2.

In 2013, we expect our non-utility energy segment operating revenue to increase approximately 2% to 3% to reflect the final approved construction costs for the Oak Creek expansion as part of the 2013 Wisconsin Rate Case. For further information, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters.

CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME

2012 vs. 2011: Corporate and other affiliates had an operating loss of $6.2 million in 2012 compared with an operating loss of $6.4 million in 2011.

2011 vs. 2010: Corporate and other affiliates had an operating loss of $6.4 million in 2011 compared with an operating loss of $6.0 million in 2010.

CONSOLIDATED OTHER INCOME AND DEDUCTIONS, NET

   Other Income and Deductions, net         2012        2011      2010
                                              (Millions of Dollars)

AFUDC - Equity                           $   35.3      $ 59.4    $ 32.5
Gain on Property Sales                        2.7         2.4       4.4
Other, net                                   (3.2 )       0.9       3.3
Total Other Income and Deductions, net   $   34.8      $ 62.7    $ 40.2

2012 vs. 2011: Other income and deductions, net decreased by approximately $27.9 million, or 44.5%, when compared to 2011. This decrease primarily relates to AFUDC - Equity related to the Glacier Hills Wind Park, which went into service in December 2011, as well as the Oak Creek AQCS project which emission control equipment went into service in March 2012 for units 5 and 6 and September 2012 for units 7 and 8.

During 2013, we expect to see a reduction in AFUDC - Equity as we expect to have fewer large construction projects.

2011 vs. 2010: Other income and deductions, net increased by approximately $22.5 million, or 56.0%, when compared to 2010. The increase in AFUDC - Equity is primarily related to the construction of the Oak Creek AQCS project and the Glacier Hills Wind Park.

  47 Wisconsin Energy Corporation


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ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL          2012 Form 10-K
         CONDITION AND RESULTS OF OPERATIONS - (Cont'd)



CONSOLIDATED INTEREST EXPENSE, NET

  Interest Expense, net        2012        2011       2010
                                  (Millions of Dollars)

Gross Interest Costs         $  264.1    $ 262.5    $ 258.7
Less: Capitalized Interest       15.9       26.7       52.3
Interest Expense, net        $  248.2    $ 235.8    $ 206.4

2012 vs. 2011: Our net interest expense increased by $12.4 million, or 5.3%, as compared to 2011 primarily because of lower capitalized interest. Our capitalized interest decreased by $10.8 million primarily because we stopped capitalizing interest on the Oak Creek AQCS project when the emission control equipment went into service in March 2012 for units 5 and 6 and September 2012 for units 7 and 8, and the Glacier Hills Wind Park which went into service in December 2011.

During 2013, we expect to see higher net interest expense because of a reduction in capitalized interest as a result of the Oak Creek AQCS project emission control equipment going into service in 2012, partially offset by the expected increase in capitalized interest associated with the biomass plant which is expected to go into service by the end of 2013.

2011 vs. 2010: Our gross interest costs increased by $3.8 million, or 1.5%, during 2011, primarily because of higher average long-term debt balances as compared to 2010. In January 2011, we issued $420 million of long-term debt and used the net proceeds to repay short-term debt incurred to finance the . . .