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WISCONSIN ELECTRIC POWER CO - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

August 1, 2014

RESULTS OF OPERATIONS -- THREE MONTHS ENDED JUNE 30, 2014

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the second quarter of 2014 with the second quarter of 2013, including favorable (better (B)) or unfavorable (worse (W)) variances: Three Months Ended June 30 Electric Revenues MWh Electric Utility 2014 B (W) 2013 2014 B (W) 2013 Operations (Millions of Dollars) (Thousands) Customer Class Residential $ 275.0$ (2.2 )$ 277.2 1,780.7 (70.7 ) 1,851.4 Small 256.6 0.4 256.2 2,085.2 (54.2 ) 2,139.4 Commercial/Industrial Large 162.9 (17.0 ) 179.9 1,854.7 (356.8 ) 2,211.5 Commercial/Industrial Other - Retail 5.4 0.1 5.3 34.8 (0.7 ) 35.5 Total Retail 699.9 (18.7 ) 718.6 5,755.4 (482.4 ) 6,237.8 Wholesale - Other 32.9 (4.3 ) 37.2 471.3 (50.6 ) 521.9 Resale - Utilities 56.5 27.7 28.8 1,483.8 593.0 890.8 Other Operating Revenues 23.0 14.4 8.6 - - - Total 812.3 19.1 793.2 7,710.5 60.0 7,650.5 Electric Customer Choice 1.4 1.4 - 627.5 627.5 - (a) Total, including electric $ 813.7$ 20.5$ 793.2 customer choice Weather -- Degree Days (b) Heating (941 Normal) 976 (53 ) 1,029 Cooling (173 Normal) 108 (30 ) 138



(a) Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.

(b) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average. Our electric utility operating revenues increased by $20.5 million, or 2.6%, when compared to the second quarter of 2013. The most significant factors that caused a change in revenues were:



A $27.7 million increase in sales for resale resulting from increased sales

into the MISO Energy Markets as a result of Michigan's alternative electric

supplier program.

A $22.1 million decrease in large commercial/industrial sales because of the

two iron ore mines switching to an alternative electric supplier in September

2013. See Factors Affecting Results, Liquidity and Capital Resources -

Electric Transmission and Energy Markets - Restructuring in Michigan, for a

discussion of the impact of industry restructuring in Michigan on our

electric sales.

A $14.4 million increase in other operating revenues, primarily driven by the

recognition of $13.0 million related to revenues under the System Support

Resource (SSR) agreement with MISO. See Factors Affecting Results, Liquidity

and Capital Resources - Electric Transmission and Energy Markets -

Restructuring in Michigan, for a discussion of the SSR payments.

Wisconsin net retail pricing increases of $9.1 million, which are primarily

related to our 2013 Wisconsin Rate Case. For information on the rate order in

the 2013 rate case and the 2014 fuel credits, see Factors Affecting Results,

Liquidity and Capital Resources -- Rates and Regulatory Matters.

Unfavorable weather decreased electric revenues by an estimated $5.3 million.

As measured by cooling degree days, the second quarter of 2014 was 21.7% cooler than the same period in 2013

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and 37.6% cooler than normal. We believe the cooler weather was the primary driver of reduced sales to our residential and small commercial/industrial customers. Sales to large commercial/industrial customers decreased by 16.1%, primarily because of the loss of the two iron ore mines in Michigan as retail electric customers. If the sales to the mines in the second quarter of 2013 are excluded, sales to our large commercial/industrial customers decreased 0.2%.



Fuel and Purchased Power

Our fuel and purchased power costs increased by $16.3 million, or 5.9%, when compared to the second quarter of 2013. This increase was primarily caused by higher generating costs driven by an increase in natural gas prices as compared to the second quarter of 2013.



Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the second quarter of 2014 with the second quarter of 2013. 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 operating revenues increased by $4.4 million, or 5.5%. Cost of gas sold increased by $3.5 million, or 7.5%, because of an 1.8% increase in the average cost of delivered gas. Three Months Ended June 30 2014 B (W) 2013 (Millions of Dollars) Gas Operating Revenues $ 83.8$ 4.4$ 79.4 Cost of Gas Sold 50.4 (3.5 ) 46.9 Gross Margin $ 33.4$ 0.9$ 32.5 The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the second quarter of 2014 with the second quarter of 2013: Three Months Ended June 30 Gross Margin Therms Gas Utility Operations 2014 B (W) 2013 2014 B (W) 2013 (Millions of Dollars) (Millions) Customer Class Residential $ 22.4 $ 0.6$ 21.8 56.3 2.8 53.5 Commercial/Industrial 6.5 - 6.5 32.6 (0.8 ) 33.4 Interruptible 0.1 - 0.1 0.7 (0.4 ) 1.1 Total Retail 29.0 0.6 28.4 89.6 1.6 88.0 Transported Gas 3.8 0.1 3.7 77.6 7.1 70.5 Other Operating 0.6 0.2 0.4 - - - Total $ 33.4 $ 0.9$ 32.5 167.2 8.7 158.5 Weather -- Degree Days (a) Heating (941 Normal) 976 (53 ) 1,029 (a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average. Our gas margin increased by $0.9 million, or approximately 2.8%, when compared to the second quarter of 2013. The unfavorable impact of weather was offset by favorable impacts tied to the economy and customer growth. As measured by heating degree days, the second quarter of 2014 was 5.2% warmer than the same period in 2013 and 3.7% colder than normal.



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Other Operation and Maintenance Expense

Our other operation and maintenance expense decreased by $16.0 million, or approximately 4.8%, when compared to the second quarter of 2013. This decrease was primarily driven by lower benefit costs.

Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $3.8 million, or approximately 5.5%, when compared to the second quarter of 2013 primarily because of an overall increase in utility plant in service. Our new biomass plant went into service in November 2013.

Treasury Grant

In December 2013, we filed an application with the United States Treasury for a Section 1603 Renewable Energy Treasury Grant (Treasury Grant) related to the construction of our biomass facility. In December 2013 we recognized income related to the Treasury Grant and we deferred as a regulatory liability the grant proceeds that would be returned to customers subsequent to December 31, 2013. In connection with our Wisconsin retail electric rates that became effective January 1, 2013, our Wisconsin retail electric customers began receiving bill credits for the expected grant proceeds plus the related tax benefits. We began to record grant income when the biomass facility was placed into service in the fourth quarter of 2013. In June 2014, we received approximately $76.2 million related to the Treasury Grant. The PSCW approved escrow accounting for the Treasury Grant and the proceeds we received that exceeded the amounts originally included in rates will be returned to customers in future rate proceedings. As noted above, our Wisconsin retail electric customers are currently receiving bill credits related to the Treasury Grant plus related tax benefits. During 2014, we are recognizing Treasury Grant income to match the bill credits related to the grant that our Wisconsin retail electric customers are receiving. Other Income, net Three Months Ended June 30 Other Income, net 2014 B (W) 2013 (Millions of Dollars) Gain on Property Sales $ 4.3$ 4.1$ 0.2 AFUDC - Equity 1.0 (3.5 ) 4.5 Other 0.6 (0.1 ) 0.7 Other Income, net $ 5.9$ 0.5$ 5.4



Other income, net increased by $0.4 million, or approximately 7.4%, when compared to the second quarter of 2013. The decrease in AFUDC - Equity is primarily related to the biomass plant going into service in November 2013.

Interest Expense, net Three Months Ended June 30 Interest Expense 2014 B (W) 2013 (Millions of Dollars) Gross Interest Costs $ 28.1$ 4.2$ 32.3 Less: Capitalized Interest 0.4 (1.6 ) 2.0 Interest Expense, net $ 27.7$ 2.6$ 30.3 Our gross interest costs decreased by $4.2 million, or approximately 13.0%, when compared to the second quarter of 2013 primarily due to lower debt levels and lower average interest rates. Our capitalized interest decreased by $1.6 million primarily because of lower construction work in progress as the biomass plant went into service in



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November 2013. As a result, our net interest expense decreased by $2.6 million, or 8.6%, as compared to the second quarter of 2013.

Income Tax Expense

For the second quarter of 2014, our effective tax rate was 34.4% compared to 36.1% for the second quarter of 2013. This decrease in our effective tax rate was primarily due to the favorable recognition of a prior year federal tax position partially offset by reduced tax benefits associated with Treasury Grant income and decreased AFUDC - Equity. For additional information, see Note G -- Income Taxes in our 2013 Annual Report on Form 10-K. RESULTS OF OPERATIONS -- SIX MONTHS ENDED JUNE 30, 2014



Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the first six months of 2014 with the first six months of 2013, including favorable (better (B)) or unfavorable (worse (W)) variances: Six Months Ended June 30 Electric Revenues MWh Electric Utility Operations 2014 B (W) 2013 2014 B (W) 2013 (Millions of Dollars) (Thousands) Customer Class Residential $ 594.2$ 13.8$ 580.4 3,943.3 47.4 3,895.9 Small Commercial/Industrial 516.6 6.5 510.1 4,338.4 19.9 4,318.5 Large Commercial/Industrial 314.1 (52.1 ) 366.2 3,647.6 (911.7 ) 4,559.3 Other - Retail 11.5 - 11.5 74.2 (0.8 ) 75.0 Total Retail 1,436.4 (31.8 ) 1,468.2 12,003.5 (845.2 ) 12,848.7 Wholesale - Other 73.7 (3.0 ) 76.7 1,076.1 37.2 1,038.9 Resale - Utilities 148.3 102.2 46.1 2,927.3 1,476.6 1,450.7 Other Operating Revenues 38.3 23.8 14.5 - - - Total 1,696.7 91.2 1,605.5 16,006.9 668.6 15,338.3 Electric Customer Choice (a) 2.8 2.8 - 1,228.7 1,228.7 - Total, including electric customer choice $ 1,699.5$ 94.0$ 1,605.5 Weather -- Degree Days (b) Heating (4,199 Normal) 5,009 509 4,500 Cooling (174 Normal) 108 (30 ) 138



(a) Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.

(b) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average. Our electric utility operating revenues increased by $94.0 million, or 5.9%, when compared to the first six months of 2013. The most significant factors that caused a change in revenues were:



A $102.2 million increase in sales for resale because of increased sales into

the MISO Energy Markets as a result of Michigan's alternative electric

supplier program and increased availability of our generating units.

A $55.6 million decrease in large commercial/industrial sales because of the

two iron ore mines switching to an alternative electric supplier in September

2013.

A $23.8 million increase in other operating revenues, primarily driven by the

recognition of $21.8 million related to revenues under the SSR agreement with

MISO.

Wisconsin net retail pricing increases of $18.2 million, which are primarily

related to our 2013 Wisconsin Rate Case.

Favorable winter weather increased electric revenues by an estimated $12.7

million.



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As measured by heating degree days, the first six months of 2014 were 11.3% colder than the same period in 2013 and 19.3% colder than normal. This favorable impact of the winter weather was partially offset by mild weather in the second quarter that reduced the cooling load. Cooling degree days decreased 21.7% during the first six months of 2014 as compared to the same period in 2013. Residential sales increased by 1.2%, primarily because of weather. Sales to large commercial/industrial customers decreased by 20.0%, primarily because of the loss of the two iron ore mines in Michigan. If the mines are excluded, sales to our large commercial/industrial customers decreased 0.4% compared to 2013.



Fuel and Purchased Power

Our fuel and purchased power costs increased by $63.9 million, or 11.6%, when compared to the first six months of 2013. This increase was primarily caused by a 4.4% increase in total MWh sales and higher generating costs driven by an increase in natural gas prices.



Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the first six months of 2014 with the first six months of 2013. 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 operating revenues increased by $149.7 million, or 58.3%, and cost of gas sold increased by $140.4 million, or 87.9%, due to colder weather and an increase in the commodity cost of natural gas. Six Months Ended June 30 2014 B (W) 2013 (Millions of Dollars) Gas Operating Revenues $ 406.3$ 149.7$ 256.6 Cost of Gas Sold 300.1 (140.4 ) 159.7 Gross Margin $ 106.2$ 9.3$ 96.9 The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the first six months of 2014 with the first six months of 2013: Six Months Ended June 30 Gross Margin Therms Gas Utility Operations 2014 B (W) 2013 2014 B (W) 2013 (Millions of Dollars) (Millions) Customer Class Residential $ 70.8 $ 5.3$ 65.5 257.1 29.3 227.8 Commercial/Industrial 25.1 3.3 21.8 148.7 22.5 126.2 Interruptible 0.2 (0.1 ) 0.3 2.3 (1.0 ) 3.3 Total Retail 96.1 8.5 87.6 408.1 50.8 357.3 Transported Gas 9.0 0.6 8.4 187.8 24.5 163.3 Other 1.1 0.2 0.9 - - - Total $ 106.2 $ 9.3$ 96.9 595.9 75.3 520.6 Weather -- Degree Days (a) Heating (4,199 Normal) 5,009 509 4,500



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

Our gas margin increased by $9.3 million, or approximately 9.6%, when compared to the first six months of 2013. This increase primarily relates to an increase in sales volumes as a result of colder weather during the first six months of 2013 that increased heating loads. We estimate that weather increased gas margins by approximately $6.5 million. As measured by heating degree days, the first six months of 2014 were 11.3% colder than the same period in 2013 and 19.3% colder than normal.



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Other Operation and Maintenance Expense

Our other operation and maintenance expense decreased by $28.7 million, or approximately 4.2%, when compared to the first six months of 2013. This decrease was primarily driven by lower benefit costs.

Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $8.1 million, or approximately 5.9%, when compared to the first six months of 2013, primarily because of an overall increase in utility plant in service. Our new biomass plant went into service in November 2013.

Treasury Grant

For a discussion of the impact of the Treasury Grant on our results of operations, see Results of Operations -- Three Months Ended June 30, 2014 -- Treasury Grant. Other Income, net Six Months Ended June 30 Other Income, net 2014 B (W) 2013 (Millions of Dollars) Gain on Property Sales $ 4.3$ 3.8$ 0.5 AFUDC - Equity 1.8 (6.9 ) $ 8.7 Other 0.6 0.3 0.3 Other Income, net $ 6.7$ (2.8 )$ 9.5



Other income, net decreased by $2.9 million, or approximately 30.5%, when compared to the first six months of 2013. The decrease in AFUDC - Equity is primarily related to the biomass plant going into service in November 2013.

Interest Expense, net Six Months Ended June 30 Interest Expense 2014 B (W) 2013 (Millions of Dollars) Gross Interest Costs $ 59.3$ 6.6$ 65.9 Less: Capitalized Interest 0.7 (3.0 ) 3.7 Interest Expense, net $ 58.6$ 3.6$ 62.2 Our gross interest costs decreased by $6.6 million, or approximately 10.0%, when compared to the first six months of 2013 primarily due to lower debt levels and lower average interest rates. Our capitalized interest decreased by $3.0 million primarily because of lower construction work in progress as the biomass plant went into service in November 2013. As a result, our net interest expense decreased by $3.6 million, or 5.8%, as compared to the first six months of 2013.



Income Tax Expense

For the first six months of 2014, our effective tax rate was 36.8% compared to 35.2% for the first six months of 2013. This increase in our effective tax rate was primarily due to reduced tax benefits associated with Treasury Grant income and decreased AFUDC - Equity. For additional information, see Note G -- Income Taxes in our 2013 Annual Report on Form 10-K. We expect our 2014 annual effective tax rate to be between 37.5% and 38.5%.



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Form 10-Q LIQUIDITY AND CAPITAL RESOURCES CASH FLOWS



The following summarizes our cash flows during the six months ended June 30:

2014 2013 (Millions of Dollars)



Cash Provided by (Used in) Operating Activities $ 518.5$ 422.7 Investing Activities $ (242.3 )$ (259.4 ) Financing Activities $ (282.2 )$ (177.6 )

Operating Activities Cash provided by operating activities increased by $95.8 million during the first six months of 2014 as compared to the same period in 2013. The increase is primarily because of $76.2 million of proceeds related to the Treasury Grant and higher net income. These items were partially offset by higher working capital requirements. Investing Activities Cash used in investing activities decreased by $17.1 million during the first six months of 2014 as compared to the same period in 2013. Our capital expenditures decreased by $6.1 million during the first six months of 2014 as compared to the same period in 2013, primarily because of the completion of the biomass plant in November 2013.



Financing Activities

Cash used in financing activities increased by $104.6 million during the first six months of 2014 as compared to the same period in 2013. We paid a $50.0 million special dividend to Wisconsin Energy during the first six months of 2014 to balance our capital structure. In addition, we decreased our short-term debt levels by $14.1 million in 2014 compared to an increase of $33.7 million during the same period in 2013.



CAPITAL RESOURCES AND REQUIREMENTS

Liquidity

We anticipate meeting our capital requirements during the remainder of 2014 and beyond 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, and equity contributions from our parent. We currently 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 currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangement, access to capital markets and internally generated cash.



We maintain a bank back-up credit facility that provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes.

As of June 30, 2014, we had approximately $494.9 million of available, undrawn lines under our bank back-up credit facility, and approximately $160.5 million of commercial paper outstanding that was supported by the available lines of credit. During the first six months of 2014, our maximum commercial paper outstanding was $401.0 million with a weighted-average interest rate of 0.21%.



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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 facility as of June 30, 2014:



Total Facility Letters of Credit Credit Available Facility Expiration

(Millions of Dollars) $ 500.0 $ 5.1 $ 494.9 December 2017



This facility has a renewal provision for two one-year extensions, subject to lender approval.

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amounts of $147 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We issued commercial paper to fund the purchase of the bonds. As of June 30, 2014, the repurchased bonds were still outstanding, but were not reported as long-term debt because they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.



Credit Rating Risk

Access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.



In June 2014, Standard and Poor's Ratings Services and Moody's Investors Service affirmed our ratings and stable ratings outlook.

Subject to other factors affecting the credit markets as a whole, we believe our current 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. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.



See Capital Resources and Requirements -- Credit Rating Risk in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2013 Annual Report on Form 10-K for additional information related to our credit rating risk.

Capital Requirements

Capital Expenditures: Capital requirements during the remainder of 2014 are expected to be principally for upgrading our electric and gas distribution systems. We estimate that we will spend approximately $530 million on capital expenditures during 2014.

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 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 9 -- Variable Interest Entities in the Notes to Consolidated Condensed Financial Statements in this report.



Contractual Obligations/Commercial Commitments: Our total contractual obligations and other commercial commitments were approximately $26.8 billion as of June 30, 2014 compared with $27.2 billion as of December 31, 2013.

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Form 10-Q FACTORS AFFECTING RESULTS, LIQUIDITY 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 2013 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, Wisconsin Energy's PTF strategy, rates and regulatory matters, electric system reliability, environmental matters, legal matters, industry restructuring and competition and other matters. POWER THE FUTURE All of the PTF units have been placed into service and are positioned to provide a significant portion of our future generation needs. We are leasing the units from We Power under long-term leases. As part of our 2013 Wisconsin Rate Case, the PSCW determined that 100% of the construction costs for the Oak Creek expansion units were prudently incurred by We Power, and approved the recovery in rates of more than 99.5% of these costs. In addition, the PSCW deferred the final decision regarding $24 million related to the Oak Creek expansion fuel flexibility project until a future rate proceeding. See Other Matters below for additional information about the fuel flexibility project. We Power assigned its warranty rights to us upon turnover of each of the Oak Creek expansion units. The warranty claim for costs incurred to repair steam turbine corrosion damage identified on both units was scheduled to go to arbitration in October 2013, but we entered into a settlement agreement with Bechtel Power Corporation (Bechtel) in June 2013 resolving the claim, as well as several other warranty claims. This settlement did not have a material impact to our financial statements. We resolved an additional warranty claim with Bechtel in April 2014 which also did not have a material impact. The parties continue to work through one remaining item.



See Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7 of our 2013 Annual Report on Form 10-K for additional information on PTF.

RATES AND REGULATORY MATTERS

2015 Wisconsin Rate Case: On May 30, 2014, we applied to the PSCW for a biennial review of costs and rates.

We engaged in settlement discussions related to this review, facilitated by PSCW Staff, with the Citizens Utility Board, the Wisconsin Industrial Energy Group and the Wisconsin Paper Council. As a result of these discussions, we agreed with the three customer groups on the following:



We are requesting a rate increase of $41.5 million (1.43%), excluding fuel,

for our Wisconsin retail electric customers in 2015; or $52.3 million (1.81%)

when including estimated fuel costs for 2015. This increase reflects an

offset of $26.2 million (0.91%) related to bill credits. Other than the

expiration of the bill credits, no adjustment to electric base rates would be

made in 2016.

We are requesting a rate decrease of $10.7 million (2.39%) for our natural

gas customers in 2015, with no rate adjustment in 2016.

We are requesting rate increases in 2015 of $0.5 million (2.10%) and $0.8

million (4.56%) for our downtown Milwaukee and Milwaukee County steam customers, respectively, with no rate adjustments in 2016. In addition, the parties have agreed that our authorized return on equity should be set at 10.2%. The agreement calls for our financial common equity component to remain the same.



2013 Wisconsin Rate Case: In March 2012, we initiated rate proceedings with the PSCW. In December 2012, the PSCW approved the following rate adjustments:

A net bill increase related to non-fuel costs for our Wisconsin retail

electric customers of approximately $70 million (2.6%) for 2013. This amount

reflects an offset of approximately $63 million (2.3%) of bill credits

related to the proceeds of the Treasury Grant, including related tax

benefits. Absent this offset, the retail electric rate increase for non-fuel

costs was approximately $133 million (4.8%) for 2013.

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An electric rate increase for our Wisconsin electric customers of

approximately $28 million (1.0%) for 2014, and a $45 million (1.6%) reduction

in bill credits.

Recovery of a forecasted increase in fuel costs of approximately $44 million

(1.6%) for 2013.

A rate decrease of approximately $8 million (1.9%) for our natural gas

customers for 2013, with no rate adjustment in 2014. The new rates reflect a

$6.4 million reduction in bad debt expense.

An increase of approximately $1.3 million (6.0%) for our downtown Milwaukee

steam utility customers for 2013 and another $1.3 million (6.0%) in 2014.

An increase of approximately $1 million (7.0%) in 2013 and $1 million (6.0%)

in 2014 for our Milwaukee County steam utility customers.

These rate adjustments were effective January 1, 2013. In addition, the PSCW indicated that our allowed return on equity would remain at 10.4%. The PSCW also approved escrow accounting treatment for the Treasury Grant. 2014 Fuel Cost Plan Request: In July 2013, we filed our 2014 fuel cost plan with the PSCW requesting authority to decrease Wisconsin retail electric customers rates approximately $36 million in the form of a fuel credit primarily related to a reduction in delivered coal costs. The plan was approved by the PSCW on December 20, 2013. Gas Cost Recovery Mechanism: Our natural gas operations operate under a Gas Cost Recovery Mechanism (GCRM) as approved by the PSCW. Generally, the GCRM allows for a dollar for dollar recovery of gas costs. The GCRM uses a modified one for one method that measures commodity purchase costs against a monthly benchmark which includes a 2% tolerance. Costs in excess of this monthly benchmark are subject to additional review by the PSCW before they can be recovered from our customers. Renewable Energy Portfolio: We constructed a 50 MW biomass facility at Domtar Corporation's Rothschild, Wisconsin paper mill site that went into commercial operation in November 2013. Wood waste and wood shavings are used to produce renewable electricity and will also support Domtar's sustainable papermaking operations. The final cost of completing this project was $269.0 million, excluding AFUDC.



See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters in Item 7 of our 2013 Annual Report on Form 10-K for additional information regarding our rates and other regulatory matters.

ELECTRIC TRANSMISSION AND ENERGY MARKETS

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 Auction Revenue Rights (ARRs) and FTRs. ARRs are allocated to market participants by MISO and FTRs are purchased through auctions. A new allocation and auction were completed for the period of June 1, 2014 through May 31, 2015. The resulting ARR valuation and the secured FTRs are expected to mitigate our transmission congestion risk for that period. Restructuring in Michigan: Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. The law limits customer choice to 10% of our Michigan retail load. The two iron ore mines are excluded from this cap. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.



The mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier in September 2013. In addition, other smaller retail customers have switched to an alternative electric supplier.

We do not expect the loss of these customers to have a material impact on our consolidated results of operations in 2014. Although the financial impact in future periods is uncertain, we expect that successful mitigation efforts and continued reasonable regulatory responses should make our net financial exposure immaterial. We have taken, and will continue to take, multiple steps to mitigate these impacts. In August 2013, we filed a request with MISO to suspend the operation of all five units at Presque Isle Power Plant (PIPP) located in the Upper Peninsula of Michigan. In October 2013, MISO informed us that the operation of all units is necessary to maintain reliability in the Upper Peninsula of Michigan. On January 30, 2014, we entered into an SSR agreement with MISO to recover costs for operating and maintaining the units. The agreement was effective February 1, 2014, has a one



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year term, and specifies monthly payments to us of $4.4 million to cover fixed costs. The agreement also provides for the payment of our variable costs to operate and maintain the plant. MISO filed the SSR agreement with the Federal Energy Regulatory Commission (FERC) on January 31, 2014, and on April 1, 2014, FERC conditionally accepted the agreement as filed, subject to further review and FERC order. We began receiving SSR payments from MISO in the second quarter retroactive to the agreement's effective date of February 1, 2014. In addition, we have been evaluating options for the long-term future of PIPP. As part of that process, we issued a request for proposals regarding the potential purchase of PIPP in January 2014. We did not receive any proposals by the March 3, 2014 deadline. Based upon our evaluation and the lack of interest to purchase the plant, on April 15, 2014, we filed a request with MISO to retire PIPP effective October 15, 2014. On May 28, 2014, MISO informed us that they had determined the operation of all five units at PIPP is necessary for reliability purposes; therefore, the units will continue to be designated as SSR units, unless an alternative solution is identified through the stakeholder planning process. We expect that MISO will again find that there are limited alternatives to continued operation of the plant at this point. We plan to enter into a new SSR agreement with MISO, effective October 15, 2014, that would be expected to cover operations for one year. The costs to comply with the Mercury and Air Toxic Standards (MATS) are expected to be included for recovery in the new SSR agreement. For additional information related to MATS, see Environmental Matters -- Air Quality -- Mercury and Other Hazardous Air Pollutants later in this report. See Factors Affecting Results, Liquidity and Capital Resources - Industry Restructuring and Competition in Item 7 of our 2013 Form 10-K for additional information regarding the impact of industry restructuring in Michigan, as well as information regarding other restructuring matters and MISO. ENVIRONMENTAL MATTERS Air Quality



National Ambient Air Quality Standards

8-hour Ozone Standards: In April 2004, the United States Environmental Protection Agency (EPA) designated 10 counties in southeastern Wisconsin as non-attainment areas for the 1997 8-hour ozone ambient air quality standard. The EPA has since redesignated all of these counties to attainment. In 2008, the EPA issued an additional, more stringent 8-hour ozone standard, and made final attainment designations for this revised standard in 2012. In April 2012 and May 2012, the EPA designated Sheboygan County and the eastern portion of Kenosha County, respectively, as 2008 8-hour ozone standard non-attainment areas. The net result of all of these actions is that construction permitting for all of our Wisconsin power plants, except the Pleasant Prairie Power Plant, is expected to be subject to less stringent permitting requirements. In addition, modifications to these facilities should no longer be required to obtain emission offsets. So long as eastern Kenosha County remains an ozone non-attainment area, the Pleasant Prairie Power Plant will continue to be subject to more stringent permitting requirements and offset provisions. In January 2010, the EPA announced its decision to further lower the 2008 8-hour ozone standard. However, in September 2011, President Obama requested the EPA to delay the reconsideration of the 8-hour ozone standard. In January 2014, environmental groups petitioned the U.S. District Court for the Northern District of California to order the EPA to propose a new ozone standard by the end of 2014 and to finalize the standard by October 2015. We expect the EPA to lower the 8-hour ozone standard from its current level. The impact, if any, of a revised standard will depend on how much it is lowered, but could result in widespread areas of the country not being able to meet the new standard. Sulfur Dioxide Standard: In June 2010, the EPA issued new hourly Sulfur Dioxide (SO2) National Ambient Air Quality Standards (NAAQS) that became effective in August 2010. This standard represented a significant change from the previous SO2 standard. The implementation guidance for the new standard, among other things, required attainment designations to be based on modeling rather than monitoring. Traditionally, attainment designations were based on monitored data. The EPA has since advised that it is revisiting this implementation guidance. In addition, various parties have submitted judicial and administrative challenges to this rule, and litigation is pending in the U.S. Court of Appeals for the D.C. Circuit challenging, among other things, the stringency of the standards and the EPA's plans to require attainment designations to be based on modeling.



June 2014 31 Wisconsin Electric Power Company

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The EPA issued two technical assistance documents for comment in 2013, and on May 13, 2014, issued the proposed Data Requirements Rule for the 1-Hour SO2 Primary NAAQS that will establish requirements for characterizing SO2 air quality in priority areas (areas with large sources of SO2 or large populations). The proposed rule describes the EPA's plans for using a combination of monitoring and modeling to make designations for areas that have not yet been designated attainment, non-attainment or unclassifiable for the 1-Hour SO2 standard. As part of the comments we filed with the EPA in July 2014, we proposed a special reliability exclusion for PIPP which would recognize the planned facility retirement, and would exclude it from further modeling or monitoring requirements and subsequent emission reductions. As proposed, the rule affords state agencies latitude in rule implementation. The way in which state agencies employ this discretion will affect each source's actual compliance obligations. In addition, the extent to which EPA exerts its "oversight" authority will also affect the final stringency of the rule and its requirements. Affected facilities would have the option of modeling or monitoring to show attainment (subject to state approval for this selection). If an affected facility is unable to show modeled attainment, then the facility would have to make emission reductions by 2017 in order to avoid a non-attainment designation. A non-attainment designation could have negative impacts for a localized geographic area, including permitting constraints for the subject source and for other new or existing sources in the area. If the source does not make reductions by 2017 and was classified as non-attainment, then it would have to make emission reductions by 2023. Alternatively, if a source opted out of modeling and instead installed monitoring, and subsequently monitored non-attainment, then it would face a 2026 compliance date. The rule does not allow any kind of facility averaging or trading program. We do not believe that we will need to make any significant additional expenditures at the majority of our generating units because of prior investments in pollution control equipment. We are evaluating the proposed rule to determine if additional controls will be required at PIPP or at our smaller generating units. Mercury and Other Hazardous Air Pollutants: In December 2011, the EPA issued the final MATS rule, which imposes stringent limitations on numerous hazardous air pollutants, including mercury, from coal and oil-fired electric generating units. We currently anticipate that only PIPP will require modifications, and are planning for the addition of dry sorbent injection systems for further control of mercury and acid gases at the plant to comply with MATS. In April 2013, we received a one year MATS compliance extension through April 16, 2016 from the Michigan Department of Environmental Quality (MDEQ). Cross-State Air Pollution Rule: In August 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR), formerly known as the Clean Air Transport Rule. This rule was proposed in 2010 to replace the Clean Air Interstate Rule (CAIR), which had been remanded to the EPA in 2008. The stated purpose of the CSAPR is to limit the interstate transport of emissions of Nitrogen Oxide (NOx) and SO2 that contribute to fine particulate matter and ozone non-attainment in downwind states through a proposed allocation plan. In February 2012, the EPA issued final technical revisions to the rule and issued a draft final rule which together delay the implementation date for certain penalty provisions that could potentially impact the PIPP and increase the number of allowances issued to the states of Michigan and Wisconsin. We and a number of other parties sought judicial review of the rule. On April 29, 2014, the United States Supreme Court issued a decision largely upholding the rule and remanding it for further proceedings consistent with the Court's order. In light of this decision and further proceedings by the appellate court, we are re-evaluating the rule and availability of allowances in Michigan for PIPP to meet its obligations to operate and provide stability to the transmission system in the Upper Peninsula of Michigan. We also expect to have excess allowances available to sell from our Wisconsin power plants. Clean Air Visibility Rule: The EPA issued the Clean Air Visibility Rule in June 2005 to address Regional Haze, or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units and how BART will be addressed in the 28 states subject to the EPA's CAIR. The pollutants from power plants that reduce visibility include fine particulate matter or compounds that contribute to fine particulate formation, NOx, SO2 and ammonia. In June 2012, the EPA promulgated a Federal Implementation Plan that approves reliance on the CSAPR to satisfy electric generating unit BART requirements for NOx and SO2. In December 2012, the EPA approved the remainder of Michigan's regional haze State Implementation Plan (SIP). In August 2012, the EPA approved Wisconsin's regional haze SIP, which also relies on the CSAPR to satisfy electric generating unit BART requirements for NOx and SO2. The U.S. Supreme Court decision on April 29, 2014 that upheld the CSAPR allows for the final regional haze rulemaking activities and requirements for NOx and SO2 to proceed. We believe we will be well positioned to meet



June 2014 32 Wisconsin Electric Power Company

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the Clean Air Visibility rule based on air quality control system additions that are already in place or planned for our generating facilities.

Valley Power Plant Conversion: In August 2012, we announced plans to convert the fuel source for Valley Power Plant (VAPP) from coal to natural gas. We currently expect the cost of this conversion to be between $65 million and $70 million, excluding AFUDC, and anticipate that the conversion will be completed by the end of 2015. We filed for a Certificate of Authority from the PSCW in April 2013, and received final written approval in March 2014. Construction is underway with the conversion of two boilers scheduled for completion in 2014, and the remaining two boilers scheduled for completion in 2015. Greenhouse Gas (GHG) Regulations: The EPA issued proposed guidelines relating to GHG emissions from existing generating units on June 18, 2014, and has announced plans to issue final rules by June 2015. The EPA also published proposed performance standards for modified and reconstructed generating units. The proposed guidelines seek to attain state-specific GHG rate reductions by 2030, and requires states to submit plans as early as June 30, 2016. Single states requesting a one year extension would be required to submit plans by June 30, 2017, and states that are part of a multi-state plan that request a two year extension would be required to submit plans by June 30, 2018. The EPA is seeking GHG rate reductions in Wisconsin of 34% and in Michigan of 31% by 2030, with interim reduction goals beginning in 2020. The proposed program consists of building blocks that include a combination of power plant efficiency improvements, increased reliance on combined cycle gas units, adding new renewable energy resources, and increased demand side management. We are in the process of reviewing the proposed guidelines to determine the potential impacts to our operations, but the guidelines as currently proposed could result in significant additional compliance costs, including capital expenditures, impact how we operate our existing fossil fueled power plants and biomass facility, and could have a material adverse impact on our operating costs. In June 2014, in Utility Air Regulatory Group v. EPA, the U.S. Supreme Court struck down a portion of the EPA's program for permitting GHG emissions under the Prevention of Significant Deterioration (PSD) and Title V programs. The Court held that a facility's GHG emissions alone cannot trigger a requirement to obtain a permit and that the EPA did not have the authority to "tailor" the statutory permitting thresholds. The Court also upheld those portions of the EPA's program that provide for implementation of GHG emissions limits based on the application of Best Available Control Technology for facilities already subject to PSD or Title V permitting requirements for other pollutants. We are evaluating the potential impact of this decision.



Water Quality

Clean Water Act: Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts. The EPA finalized rules for new facilities (Phase I) in 2001. Final rules for cooling water intake systems at existing facilities (Phase II) were promulgated in 2004. However, as a result of litigation, the EPA withdrew the Phase II rule in July 2007 and advised states to use their best professional judgment in making BTA decisions while the rule remains suspended. The EPA proposed a new Phase II rule in 2011, and issued the final Phase II rule on May 16, 2014. The new rule will apply to all of our existing generating facilities with cooling water intake structures, except for the Oak Creek expansion units, which were permitted under the Phase I rules. The new rule allows facility owners to select from seven options available to meet the impingement mortality (IM) reduction standard. BTA determinations will be made over the next several years by the WDNR and MDEQ, subject to EPA oversight, when facility permits are reissued. Based upon our preliminary assessment, we believe that the existing technologies at our generating facilities will allow us to demonstrate that, other than VAPP, all of our facilities satisfy the IM BTA standard. We plan to install fish protection screens at VAPP that we expect will meet the IM BTA standard. The BTA determinations for entrainment mortality (EM) reduction will be made by the WDNR and MDEQ on a case-by-case basis. The new rule requires state permitting agencies to determine EM BTA on a site-specific basis taking into consideration several factors. Because the entrainment reduction standard is a site-specific determination, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new requirements.



June 2014 33 Wisconsin Electric Power Company

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See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 of our 2013 Annual Report on Form 10-K for additional information regarding environmental matters affecting our operations.

OTHER MATTERS

Oak Creek Expansion Fuel Flexibility Project: The Oak Creek expansion units were designed and permitted to use bituminous coal from the Eastern United States. Market forces have resulted in a significant price differential between bituminous and sub-bituminous coals. We received a new air construction permit from the WDNR to modify the Oak Creek expansion units for potential future use of sub-bituminous coal. In 2013, we began testing various combinations of sub-bituminous coal and bituminous coal to identify any equipment limitations, and making equipment modifications to the units. In February 2013, the Sierra Club and the Midwest Environmental Defense Center filed a petition for a contested case hearing with the WDNR to challenge the issuance of the air construction permit. The WDNR has granted that petition, but a hearing has not yet been scheduled. Paris Generating Station Units 1 and 4 Temporary Outage: Between 2000 and 2002, we replaced the blades on the four Paris Generating Station (PSGS) combustion turbine generators with blades that were approximately 7% more efficient. Although the work was performed as routine maintenance that we did not believe required a construction permit at the time and the plant has not been operated to use the potential additional capacity, the WDNR has indicated that it now considers this maintenance to be a modification requiring a construction permit. The WDNR issued a Notice of Violation (NOV) to us in January 2013 alleging violations of the new source review rules and certain Wisconsin environmental rules. At the same time, the WDNR also issued an administrative order that prohibits us from operating PSGS Units 1 and 4 until the earlier of: (1) Units 1 and 4 achieve the applicable NOx emission rates; (2) the Wisconsin regulations are revised so that Units 1 and 4 can achieve the emission limits or are no longer subject to the limits; (3) the alleged modification is resolved through a consent decree; or (4) a court decides that the blade replacement project was not a major modification. We are presently evaluating alternative approaches to return these peaking units to service, and expect Units 1 and 4 to remain out of service until at least the end of this summer. In December 2013, Act 91 was signed into law in Wisconsin, creating a process by which the EPA and WDNR may revise the regulations applicable to Units 1 and 4 and allow those units to restart. In February 2013, the Sierra Club filed for a contested case hearing with the WDNR in connection with the administrative order. The WDNR has granted that petition, but a hearing has not yet been scheduled. In addition, in May 2013, the WDNR referred the matter to the Wisconsin Department of Justice for alleged violations of air management statutes and rules. In June 2014, we settled with the Department of Justice and paid $50,000 in costs and penalties.



PSGS Units 2 and 3 remain available for operation because the turbine blade maintenance on these units occurred prior to a rule change in 2001.


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