News Column

WISCONSIN PUBLIC SERVICE CORP - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

August 7, 2014

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our Annual Report on Form 10-K for the year ended December 31, 2013. SUMMARY We are a regulated electric and natural gas utility and a wholly owned subsidiary of Integrys Energy Group, Inc. We derive revenues primarily from the distribution and sale of electricity and natural gas to retail customers. We also provide wholesale electric service to numerous utilities and cooperatives for resale. RESULTS OF OPERATIONS Earnings Summary Three Months Ended June 30 Change in 2014 Six Months Ended June 30 Change in 2014 (Millions) 2014 2013 Over 2013 2014 2013 Over 2013 Electric utility operations $ 14.9$ 23.1 (35.5 )% $ 42.1$ 48.8 (13.7 )% Natural gas utility operations (0.1 ) 0.3 N/A 20.6 17.4 18.4 % Other operations 2.3 2.5 (8.0 )% 4.7 4.3 9.3 % Net income attributed to common shareholder $ 17.1$ 25.9 (34.0 )% $ 67.4$ 70.5 (4.4 )%



Second Quarter 2014 Compared with Second Quarter 2013

The $8.8 million decrease in our earnings was driven by:

A $9.0 million after-tax increase in electric and natural gas utility

operating expenses, driven by an increase in maintenance expense. The

increase was primarily due to planned major outages at the Fox Energy Center

and Weston 4 plant in 2014.

A $2.9 million after-tax increase in interest expense on long-term debt,

driven by higher average outstanding long-term debt during 2014.

A $3.6 million after-tax decrease in electric utility margins due to

variances in retail sales volumes, net of decoupling. Our decoupling mechanism was terminated effective January 1, 2014.



Partially offsetting these decreases was a $5.1 million after-tax increase in margins related to our 2014 PSCW electric rate order effective January 1, 2014.

Six Months 2014 Compared with Six Months 2013

The $3.1 million decrease in our earnings was driven by:

A $20.4 million after-tax increase in electric and natural gas utility

operating expenses. The increase was driven by higher maintenance expense,

primarily due to planned major outages at the Fox Energy Center and Weston 4

plant. Other operating costs associated with the Fox Energy Center also

contributed to the increase. We acquired the Fox Energy Center at the end of

the first quarter of 2013, and the costs associated with it are being recovered through the rate order mentioned below.



A $5.4 million after-tax increase in interest expense on long-term debt,

driven by higher average outstanding long-term debt during 2014.

These decreases were partially offset by:

A $13.4 million after-tax increase in margins related to our 2014 PSCW

electric rate order effective January 1, 2014.

An $8.3 million after-tax increase in natural gas utility margins due to

variances in sales volumes, net of decoupling. The increase was driven by

colder than normal weather in 2014 as our decoupling mechanism was terminated

effective January 1, 2014. 22



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Electric Utility Segment Operations

Three Months Ended June 30



Change in 2014 Six Months Ended June 30 Change in 2014 (Millions, except degree days) 2014

2013 Over 2013 2014 2013 Over 2013 Revenues $ 291.4$ 306.4



(4.9 )% $ 612.8$ 614.3 (0.2 )% Fuel and purchased power costs 109.8

127.7 (14.0 )% 240.4 265.9 (9.6 )% Margins 181.6 178.7 1.6 % 372.4 348.4 6.9 % Operating and maintenance expense 112.5 100.4 12.1 % 217.7 191.6 13.6 % Depreciation and amortization expense 24.2 23.8 1.7 % 47.7 43.3 10.2 % Taxes other than income taxes 11.3 10.7 5.6 % 22.6 22.1 2.3 % Operating income 33.6 43.8 (23.3 )% 84.4 91.4 (7.7 )% Miscellaneous income 2.8 2.1 33.3 % 6.3 3.7 70.3 % Interest expense 11.2 7.7 45.5 % 22.1 15.9 39.0 % Other expense (8.4 ) (5.6 ) 50.0 % (15.8 ) (12.2 ) 29.5 % Income before taxes $ 25.2$ 38.2



(34.0 )% $ 68.6$ 79.2 (13.4 )%

Sales in kilowatt-hours Residential 627.5 631.7 (0.7 )% 1,446.3 1,382.5 4.6 % Commercial and industrial 1,969.6 1,958.0 0.6 % 3,926.2 3,883.2 1.1 % Wholesale 821.3 1,245.8 (34.1 )% 1,601.0 2,391.8 (33.1 )% Other 6.4 6.8 (5.9 )% 15.8 15.9 (0.6 )% Total sales in kilowatt-hours 3,424.8 3,842.3 (10.9 )% 6,989.3 7,673.4 (8.9 )%



Weather

Actual heating degree days 1,020 1,107 (7.9 )% 5,535 4,910 12.7 % Normal heating degree days 975 978 (0.3 )% 4,621 4,621 - % Actual cooling degree days 109 131 (16.8 )% 109 131 (16.8 )% Normal cooling degree days 141 137 2.9 % 141 137 2.9 % Electric utility margins are defined as electric utility operating revenues less fuel and purchased power costs. Management believes that electric utility margins provide a more meaningful basis for evaluating electric utility operations than electric utility operating revenues. To the extent changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in operating revenues.



Second Quarter 2014 Compared with Second Quarter 2013

Margins

Electric utility segment margins increased $2.9 million.

Margins increased approximately $8 million related to our PSCW rate order,

effective January 1, 2014. See Note 15, Regulatory Environment, for more

information. Excluding the impacts from fuel and purchased power costs, our PSCW rate order resulted in an approximate $20 million increase in margins. The increase was driven by the costs to operate the Fox Energy Center, which were included in rates beginning in 2014. Although the PSCW approved an electric rate decrease, the rate decrease was driven by



2013 fuel cost over-collections and 2012 decoupling over-collections

that are being refunded to customers in 2014 and have no impact on margins. Partially offsetting this increase was an approximate $12 million decrease in margins related to fuel and purchased power costs. The



decrease was driven by approximately $8 million of fuel and purchased

power costs that are not included in the fuel rule recovery mechanism.

In 2013, purchased power costs were lower than rate-case approved

amounts as a result of the acquisition of Fox Energy Company LLC.

Margins were further decreased by approximately $4 million related to

fuel and purchased power cost under-collections in 2014, compared with over-collections in 2013. Under the fuel rule, we can only defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates.



Margins decreased approximately $6 million related to sales volume variances,

net of the impact of decoupling. The decrease was primarily driven by the

termination of our decoupling mechanism, effective January 1, 2014. See

Note 15, Regulatory Environment, for more information. Margins from our large

commercial and industrial customers also decreased, driven by lower use per

customer in the second quarter of 2014. Our decoupling mechanism did not

cover large commercial and industrial customers. 23



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Operating Income

Operating income at the regulated electric utility segment decreased $10.2 million. The decrease was driven by a $13.1 million increase in operating expenses, partially offset by the $2.9 million increase in margins discussed above.

The increase in operating expenses was driven by:

A $12.5 million increase in maintenance expense, primarily due to planned

major outages at the Fox Energy Center and Weston 4 plant in 2014, as well as

maintenance at certain other generation plants.

A $1.4 million net increase in electric transmission expense. Increases in

electric transmission expense of $2.9 million were partially offset by

deferrals approved by the PSCW of $1.5 million related to system support

resource costs for retail customers. See Other Future Considerations, Presque

Isle System Support Resources (SSR) Costs, for more information.

Amortization expense of $1.4 million for a regulatory asset related to the

fee paid for the early termination of the power purchase agreement in

connection with the Fox Energy Center acquisition. Margins increased by an

equal amount, resulting in no impact on earnings.

A $0.7 million net increase in employee benefit costs. The increase in

employee benefit costs was driven by:

The quarter-over-quarter impact of the deferral of employee benefit costs

in 2013 and the related amortization in 2014, which together increased

employee benefit costs $3.6 million. In 2013, we deferred certain increases in pension and other employee benefit costs as a result of our 2013 rate order with the PSCW. We began amortizing this regulatory asset in 2014.



Higher stock-based compensation expense of $2.6 million, which was driven

by an increase in the fair value of awards accounted for as liabilities.

The increase in fair value resulted from an increase in Integrys Energy

Group's stock price.



Other employee benefit costs decreased $5.5 million in the first quarter

of 2014. This decrease was partially driven by a remeasurement of certain

other postretirement benefit plans. See Note 10, Employee Benefit Plans,

for more information. Higher discount rates assumed in 2014 also contributed to the overall decrease in employee benefit costs. These increases were partially offset by a $4.9 million decrease in operating expense due to the quarter-over-quarter impact of the 2013 deferral of the net difference between actual and rate case-approved costs resulting from the purchase of the Fox Energy Center. The 2013 PSCW rate order did not reflect this purchase or the related termination of the power purchase agreement. However, we did receive PSCW approval to defer ownership costs above or below our power purchase agreement expenses in 2013.



Other Expense

Other expense increased $2.8 million. The primary driver was a $4.3 million increase in interest expense on long-term debt, driven by higher average outstanding long-term debt during the second quarter of 2014. An increase in AFUDC of $0.9 million partially offset the increase in interest expense, largely due to environmental compliance projects at the Columbia plant.



Six Months 2014 Compared with Six Months 2013

Margins

Electric utility segment margins increased $24.0 million, driven by:

An approximate $22 million increase in margins related to our PSCW rate

order, effective January 1, 2014. See Note 15, Regulatory Environment, for

more information.



Excluding the impacts from fuel and purchased power costs, the PSCW rate

order resulted in an approximate $36 million increase in margins. The increase was driven by the costs to operate the Fox Energy Center, which



were included in rates beginning in 2014. Although the PSCW approved an

electric rate decrease, the rate decrease was driven by 2013 fuel cost over-collections and 2012 decoupling over-collections that are being refunded to customers in 2014 and have no impact on margins. Partially offsetting this increase was an approximate $14 million decrease in margins related to fuel and purchased power costs. The decrease was partially driven by approximately $7 million of fuel and



purchased power costs that are not included in the fuel rule recovery

mechanism. In 2013, purchased power costs were lower than rate-case

approved amounts as a result of the acquisition of Fox Energy Company

LLC. Margins were further decreased by approximately $7 million related

to fuel and purchased power cost under-collections in 2014, compared with

over-collections in 2013. Under the fuel rule, we can only defer under or

over-collections of certain fuel and purchased power costs that exceed a

2% price variance from the costs included in rates. 24



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An approximate $4 million increase in wholesale margins driven by higher

prices. Wholesale prices increased primarily due to the pass-through of increased generation costs to these customers.



A partially offsetting decrease in margins of approximately $3 million

related to sales volume variances, net of the impact of decoupling. The

decrease was primarily driven by the termination of our decoupling mechanism,

effective January 1, 2014. See Note 15, Regulatory Environment, for more

information. Margins from our large commercial and industrial customers also

decreased, driven by lower use per customer in 2014. Our decoupling mechanism

did not cover large commercial and industrial customers. These decreases were

partially offset by the positive impact that colder than normal weather in 2014 had on margins at the electric utility.



Operating Income

Operating income at the regulated electric utility segment decreased $7.0 million. The decrease was driven by a $31.0 million increase in operating expenses, partially offset by the $24.0 million increase in margins discussed above.

The increase in operating expenses was driven by:

A $22.1 million increase in maintenance expense, primarily due to planned

major outages at the Pulliam plant, Fox Energy Center, and Weston 4 plant in

2014, as well as maintenance at certain other WPS generation plants.

A $4.4 million increase in depreciation and amortization expense, mainly due

to the acquisition of the Fox Energy Center at the end of the first quarter

of 2013.



A $3.8 million increase in various costs associated with the acquisition and

operation of the Fox Energy Center. Included in this amount is the

amortization of the regulatory asset related to the fee paid for the early

termination of the power purchase agreement in connection with the

acquisition. Recovery of the amortization was included in the new rates.

A $3.6 million net increase in electric transmission expense. Increases in

electric transmission expense of $6.6 million were partially offset by

deferrals approved by the PSCW of $3.0 million related to system support

resource costs for retail customers. See Other Future Considerations, Presque

Isle System Support Resources (SSR) Costs, for more information.

These increases were partially offset by:

A $3.3 million decrease due to the period-over-period impact of the 2013

deferral of the net difference between actual and rate case-approved costs

resulting from the purchase of the Fox Energy Center. The 2013 PSCW rate

order did not reflect this purchase or the related termination of the power

purchase agreement. However, we did receive PSCW approval to defer ownership

costs above or below our power purchase agreement expenses in 2013.

A $2.0 million net decrease in employee benefit costs. Employee benefit costs

other than stock-based compensation (discussed below) decreased $11.4 million

in 2014. This decrease was partially driven by a remeasurement of certain

other postretirement benefit plans. See Note 10, Employee Benefit Plans, for

more information. Higher discount rates assumed in 2014 also contributed to

the overall decrease in employee benefit costs. This decrease was partially

offset by:



Higher stock-based compensation expense of $2.1 million, which was driven

by an increase in the fair value of awards accounted for as liabilities.

The increase in fair value resulted from an increase in Integrys Energy Group's stock price.



The period-over-period impact of a deferral of employee benefit costs in

2013 and the related amortization in 2014, which together increased

employee benefit costs by $7.3 million. In 2013, we deferred certain

increases in pension and other employee benefit costs as a result of our

2013 rate order with the PSCW. We began amortizing this regulatory asset

in 2014. Other Expense Other expense increased $3.6 million. The primary driver was a $7.9 million increase in interest expense on long-term debt, driven by higher average outstanding long-term debt during 2014. An increase in AFUDC of $3.7 million partially offset the increase in interest expense, largely due to the installation of the ReACTTM emission control technology at the Weston 3 plant and environmental compliance projects at the Columbia plant. 25



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Natural Gas Utility Segment Operations

Three Months Ended June 30 Change



in 2014 Six Months Ended June 30 Change in 2014 (Millions, except degree days) 2014

2013 Over 2013 2014 2013 Over 2013 Revenues $ 70.1$ 63.8 9.9 % $ 308.8$ 191.1 61.6 % Natural gas purchased for resale 43.9 39.3 11.7 % 223.7 115.7 93.3 % Margins 26.2 24.5 6.9 % 85.1 75.4 12.9 % Operating and maintenance expense 18.0 16.3 10.4 % 34.9 32.2 8.4 % Depreciation and amortization expense 4.1 4.0 2.5 % 8.1 7.9 2.5 % Taxes other than income taxes 1.3 1.2 8.3 % 2.6 2.5 4.0 % Operating income 2.8 3.0 (6.7 )% 39.5 32.8 20.4 % Miscellaneous income 0.1 - N/A 0.1 0.1 - % Interest expense 2.6 2.2 18.2 % 5.2 4.3 20.9 % Other expense (2.5 ) (2.2 ) 13.6 % (5.1 ) (4.2 ) 21.4 % Income before taxes $ 0.3$ 0.8



(62.5 )% $ 34.4$ 28.6 20.3 %

Retail throughput in therms Residential 39.9 40.9 (2.4 )% 181.8 159.3 14.1 % Commercial and industrial 24.9 24.6 1.2 % 112.1 91.6 22.4 % Other 4.7 5.5 (14.5 )% 14.6 11.2 30.4 % Total retail throughput in therms 69.5 71.0 (2.1 )% 308.5 262.1 17.7 % Transport throughput in therms Commercial and industrial 79.8 80.1 (0.4 )% 200.6 192.5 4.2 % Total throughput in therms 149.3 151.1 (1.2 )% 509.1 454.6 12.0 % Weather Actual heating degree days 1,020 1,107 (7.9 )% 5,535 4,910 12.7 % Normal heating degree days 975 978 (0.3 )% 4,621 4,621 - % Natural gas utility margins are defined as natural gas utility operating revenues less the cost of natural gas purchased for resale. Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. There was an approximate 14% and 64% increase in the average per-unit cost of natural gas sold during the three and six months ended June 30, 2014, respectively, which had no impact on margins.



Second Quarter 2014 Compared with Second Quarter 2013

Margins

Natural gas utility segment margins increased $1.7 million, driven by the approximate $2 million combined effect of the change in weather quarter over quarter, the impact of higher weather-normalized volumes, and the impact of our decoupling mechanism. In 2014, our margins were positively impacted by colder than normal weather as we no longer had a decoupling mechanism in place, effective January 1, 2014. Higher use per customer and an increase in customers also contributed to the increase in margins in 2014.



Operating Income

Operating income at the natural gas utility segment decreased $0.2 million. This decrease was driven by a $1.9 million increase in operating expenses, partially offset by the $1.7 million increase in margins discussed above.



The increase in operating expenses was driven by:

A $0.6 million increase in natural gas distribution costs, partially due

to increased labor costs related to wage increases and increased meter

maintenance.



A $0.3 million increase in employee benefit costs driven by:

The $1.1 million negative quarter-over-quarter impact of the deferral of employee benefit costs in 2013 and the related 26



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amortization in 2014. In 2013, we deferred certain increases in pension and other employee benefit costs as a result of our 2013 rate order with the PSCW. We began amortizing this regulatory asset in 2014.

A $0.7 million increase in stock-based compensation expense, due to the quarter-over-quarter increase in the fair value of awards accounted for as liabilities. The increase in fair value resulted from an increase in Integrys Energy Group's stock price. These increases were partially offset by a $1.5 million decrease in other employee benefit costs, driven in part by the



remeasurement of

certain postretirement benefit plans in the first quarter of 2014. See Note 10, Employee Benefit Plans, for more information. Higher discount rates assumed in 2014 also contributed to the decrease.



There were no other individually significant items that impacted operating expenses.

Six Months 2014 Compared with Six Months 2013

Margins

Natural gas utility segment margins increased $9.7 million.

The combined effect of the change in weather period over period, the impact of higher weather-normalized volumes, and the impact of our decoupling mechanism increased margins approximately $14 million. In 2014, our margins were positively impacted by colder than normal weather as we no longer had a decoupling mechanism in place, effective January 1, 2014.



Higher use per customer and an increase in customers also contributed to

the increase in margins in 2014.



Margins were negatively impacted by approximately $3 million related to

our rate order, effective January 1, 2014. The decrease in margins was driven by a natural gas rate decrease and rate design changes in 2014. Although the PSCW approved a net rate increase, it was driven by the recovery of the 2012 decoupling under-collections to be recovered from



customers in 2014, which has no impact on margins. See Note 15, Regulatory

Environment, for more information.

Operating Income

Operating income at the natural gas utility segment increased $6.7 million. This increase was primarily driven by the $9.7 million increase in margins discussed above, partially offset by a $3.0 million increase in operating expenses.



The increase in operating expenses was driven by a $1.4 million increase in natural gas distribution costs, partially due to increased labor costs related to wage increases and increased meter maintenance.

This increase was partially offset by a $0.2 million decrease in employee benefit costs driven by:

A $2.9 million decrease in pension and other postretirement costs, driven

in part by the remeasurement of certain postretirement benefit plans in the first quarter of 2014. See Note 10, Employee Benefit Plans, for more



information. Higher discount rates assumed in 2014 also contributed to the

decrease. This decrease was partially offset by the $2.1 million negative period-over-period impact of the deferral of employee benefit costs in



2013 and the related amortization in 2014. In 2013, we deferred certain

increases in pension and other employee benefit costs as a result of our

2013 rate order with the PSCW. We began amortizing this regulatory asset

in 2014.



There were no other individually significant items that impacted operating expenses.

Other Segment Operations

Three Months Ended June 30 Change in Six Months Ended June 30 Change in 2014 Over 2014 Over (Millions) 2014 2013 2013 2014 2013 2013 Operating income $ 0.1 $ 0.1 - % $ 0.2$ 0.1 100.0 % Other income 3.2 3.4 (5.9 )% 6.5 6.1 6.6 % Income before taxes $ 3.3 $ 3.5 (5.7 )% $ 6.7$ 6.2 8.1 %



There was no material change in income before taxes for other segment operations for all periods presented.

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Provision for Income Taxes

Three Months Ended June 30 Six Months Ended June 30 2014 2013 2014 2013 Effective tax rate 37.8 % 37.2 % 37.1 % 36.8 %



There was no material change in our effective tax rate for all periods presented.

LIQUIDITY AND CAPITAL RESOURCES We believe we have adequate resources to fund ongoing operations and future capital expenditures. These resources include cash balances, liquid assets, operating cash flows, access to debt capital markets, and available borrowing capacity under existing credit facilities. Our borrowing costs can be impacted by short-term and long-term debt ratings assigned by independent credit rating agencies, as well as the market rates for interest. Our operating cash flows and access to capital markets can be impacted by macroeconomic factors outside of our control. Operating Cash Flows



During the six months ended June 30, 2014, net cash provided by operating activities was $126.9 million, compared with $91.7 million during the same period in 2013. The $35.2 million increase in net cash provided by operating activities was driven by:

A $97.8 million increase in cash collections from customers, mainly due to

rate increases, higher commodity prices, and the colder than normal weather

in 2014. This variance includes the impact of $12.4 million of natural gas

cost over-collections from customers in 2013.

The positive period-over-period impact of a $50.0 million payment in 2013 for

the early termination of a tolling agreement in connection with the purchase

of Fox Energy Company LLC.

A $7.2 million increase in cash received from income taxes, primarily driven

by a federal income tax refund received in the first quarter of 2014 for an

amended return. Quarterly income tax estimate payments and a federal income

tax extension payment made in 2014 partially offset the tax refund received.

These increases in cash were partially offset by:

A $78.0 million decrease in cash due to higher costs of natural gas, fuel,

and purchased power in 2014. Additional cash was used in 2014 due to higher

energy prices and the colder than normal weather. To meet the higher energy

needs of customers, we purchased fuel and purchased power at higher prices

than expected in 2014, which were not yet reflected in the rates charged to

our electric customers. This resulted in a period-over-period variance in

under-collection from electric utility customers of $12.5 million. These

under-collections were higher in 2014 than in 2013.

A $12.6 million decrease in cash related to increased operating and

maintenance costs in 2014. The decrease was driven by increases in electric

utility maintenance and operating costs associated with the Fox Energy Center, which we acquired at the end of the first quarter of 2013.



An $8.4 million decrease in cash from various deferrals, primarily for system

support resource costs, pre-certification costs for a potential new natural

gas combined cycle generating unit, and the net difference between actual and

rate case-approved costs resulting from the purchase of the Fox Energy Center.



An $8.7 million increase in contributions to pension and other postretirement

benefit plans.



A $5.7 million increase in cash paid for interest, primarily driven by an

increase in long-term debt in 2014 as compared with 2013.

A $5.7 million decrease in cash from customer prepayments and credit balances

due to higher natural gas prices and higher sales volumes in 2014. During

2014, customers used more energy than they paid for under budget billing

programs. Investing Cash Flows During the six months ended June 30, 2014, net cash used for investing activities was $126.9 million, compared with $432.7 million during the same period in 2013. The $305.8 million decrease in net cash used for investing activities was primarily due to $391.6 million of cash used in 2013 to purchase Fox Energy Company LLC. See Note 3, Acquisition of Fox Energy Center, for more information regarding this purchase. Partially offsetting the decrease in net cash used was the period-over-period negative impact of the receipt of a $69.0 million Section 1603 Grant for the Crane Creek wind project in 2013 and a $17.3 million increase in cash used for other capital expenditures (discussed below). 28



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Capital Expenditures

Capital expenditures by business segment for the six months ended June 30 were as follows: Reportable Segment (millions) 2014 2013 Change in 2014 Over 2013 Electric utility $ 111.0$ 489.4 $ (378.4 ) Natural gas utility 18.2 14.1 4.1 WPS consolidated $ 129.2$ 503.5 $ (374.3 ) The decrease in capital expenditures at the electric utility segment in 2014 compared with 2013 was primarily due to our purchase of Fox Energy Company LLC in 2013. Capital expenditures related to environmental compliance projects at the Columbia plant also decreased in 2014. Increased expenditures at the electric utility segment related to the ReACTTM project at Weston 3 in 2014 partially offset the decrease.



Financing Cash Flows

During the six months ended June 30, 2014, net cash provided by financing activities was $14.6 million, compared with $339.1 million for the same period in 2013. The $324.5 million decrease in net cash provided by financing activities was driven by:

A $200.0 million decrease in borrowings under our term credit facility, which

were used in 2013 to partially finance the acquisition of Fox Energy Company

LLC.



A $160.0 million decrease in equity contributions from Integrys Energy Group,

which were used to support the acquisition of Fox Energy Company LLC in 2013.

A $17.0 million decrease in net borrowings of commercial paper in 2014.

These decreases in cash were partially offset by the period-over-period impact of:

A $35.0 million return of capital to parent in 2013.

A $22.0 million repayment of long-term debt in 2013.

Significant Financing Activities

For information on short-term debt, see Note 7, Short-Term Debt and Lines of Credit.

There were no significant changes in long-term debt during 2014.

Credit Ratings

Our current credit ratings are listed in the table below: Credit Ratings Standard & Poor's Moody's Issuer credit rating A- A1 First mortgage bonds N/A Aa2 Senior secured debt A Aa2 Preferred stock BBB A3 Commercial paper A-2 P-1



Credit ratings are not recommendations to buy or sell securities. They are subject to change and each rating should be evaluated independent of any other rating.

On January 31, 2014, Moody's raised the following credit ratings. Our issuer rating was raised to "A1" from "A2," our first mortgage bonds rating was raised to "Aa2" from "Aa3," our senior secured debt rating was raised to "Aa2" from "Aa3," and our preferred stock rating was raised to "A3" from "Baa1." The upgrade in ratings reflects Moody's views of the regulatory provisions in Wisconsin that are consistent with a generally improving regulatory environment for electric and natural gas utilities in the United States. 29



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Future Capital Requirements and Resources

Contractual Obligations

The following table shows our contractual obligations as of June 30, 2014, including those of our subsidiary:

Payments Due By Period Total Amounts 2019 and (Millions) Committed 2014 2015 to 2016 2017 to 2018 Later Years Long-term debt principal and interest payments (1) $ 2,370.9$ 28.7$ 231.2$ 215.7$ 1,895.3 Operating lease obligations 15.7 0.3 1.1 1.1 13.2 Energy and transportation purchase obligations (2) 1,286.2 86.0 241.2 234.6 724.4 Purchase orders (3) 445.8 340.3 93.3 12.2 - Pension and other postretirement funding obligations (4) 5.5 3.0 2.5 - - Total contractual cash obligations $ 4,124.1$ 458.3$ 569.3$ 463.6$ 2,632.9 (1) Represents bonds and notes issued. We record all principal obligations on the balance sheet.



(2) The costs of energy and transportation purchase obligations are expected to

be recovered in future customer rates.

(3) Includes obligations related to normal business operations and large

construction obligations.

(4) Obligations for pension and other postretirement benefit plans, other than

the Integrys Energy Group Retirement Plan, cannot reasonably be estimated

beyond 2016. The table above does not reflect estimated future payments related to the manufactured gas plant remediation liability of $70.0 million at June 30, 2014, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 9, Commitments and Contingencies, for more information about environmental liabilities.



Capital Requirements

Projected capital expenditures by segment for 2014 through 2016, including amounts expended through June 30, 2014, are as follows: (Millions)

2014 2015 2016 Total Electric Utility Distribution, transmission and energy supply operations projects $ 133$ 137$ 131$ 401 Environmental Projects * 150 135 105 390 Other projects 7 11 158 176 Natural Gas Utility Distribution projects 36 30 37 103 Other projects 1 1 1 3 Total capital expenditures $ 327$ 314$ 432$ 1,073 * This primarily relates to the installation of ReACTTM emission control technology at Weston 3 and the installation of scrubbers at the Columbia plant. All projected capital and investment expenditures are subject to periodic review and may vary significantly from the estimates, depending on a number of factors. These factors include, but are not limited to, environmental requirements, regulatory constraints and requirements, changes in tax laws and regulations, market volatility, and economic trends.



Capital Resources

Management prioritizes the use of capital and debt capacity, determines cash management policies, uses risk management strategies to hedge the impact of volatile commodity prices, and makes decisions regarding capital requirements in order to manage our liquidity and capital resource needs. We plan to meet our capital requirements for the period 2014 through 2016 primarily through internally generated funds (net of forecasted dividend payments), debt financings, and equity infusions from Integrys Energy Group. We plan to keep debt to equity ratios at levels that can support current credit ratings and corporate growth.



We currently have two shelf registration statements. Under these registration statements, we may issue up to $50.0 million of additional senior debt securities and up to $30.0 million of preferred stock. Amounts, prices, and terms will be determined at the time of future offerings.

At June 30, 2014, we were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future.

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Presque Isle System Support Resources (SSR) Costs

In August 2013, Wisconsin Electric Power Company (Wisconsin Electric Power) submitted to MISO a notice, in which Wisconsin Electric Power stated its intention to suspend the operation of Units 5 through 9 of its Presque Isle generating facility for 16 months, starting February 1, 2014. MISO completed its reliability analysis and notified Wisconsin Electric Power in October 2013 that the Presque Isle facilities are required for reliability and would be SSR-designated until alternatives could be implemented to mitigate reliability issues. The SSR Tariff provisions permit MISO to negotiate compensation for generation resources where a market participant desires to retire or suspend operation of the facility but MISO determines that it is needed to maintain system reliability. In exchange for keeping the units in service, MISO will compensate Wisconsin Electric Power by allocating the SSR costs associated with the operation of the Presque Isle units to regulated and nonregulated load serving entities, including us, based on load ratio share within the ATC footprint. In January 2014, MISO submitted a new rate schedule to the FERC reflecting this. Currently, our allocated SSR costs are estimated at $9 million annually. However, in late July 2014, the FERC granted a complaint filed by the PSCW requesting to change the allocation methodology to the various parties based on a new load-shed analysis to be completed by MISO. The revised methodology will likely result in increased SSR costs. In April 2013, the PSCW ordered that SSR costs for our retail customers should be deferred until December 31, 2015. At that time, the PSCW will determine the appropriate ratemaking treatment. As of June 30, 2014, $3.0 million of SSR costs have been deferred for future recovery. SSR costs for our Michigan customers are being recovered through the Power Supply Cost Recovery mechanism. SSR costs for our wholesale customers are being recovered through formula rates.



MISO Transmission Owner Return on Equity Complaint

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting, among other things, to reduce the base return on equity (ROE) used by MISO transmission owners, including ATC, to 9.15%. ATC's current authorized ROE is 12.2%. In June 2014, the FERC issued a decision, in regard to a similar complaint, to reduce the base ROE for New England transmission owners from their existing rate of 11.14% to 10.57%. In this decision, the FERC used a revised method for determining the appropriate ROE for FERC-jurisdictional electric utilities, which incorporates both short-term and long-term measures of growth in dividends. The FERC has stated that it expects future decisions on pending complaints related to similar ROE issues will be guided by the New England transmission decision. Any change to ATC's return on equity and capital structure could result in lower equity income and dividends from ATC in the future. We are currently unable to determine the timing and nature of any FERC actions related to this complaint.



Wisconsin Fuel Rule Under-collection "Cap"

We use a "fuel window" mechanism to recover fuel and purchased power costs for our Wisconsin retail electric operations. Under the fuel window rule, actual fuel and purchased power costs that exceed a 2% variance from costs included in the rates charged to customers are deferred for recovery or refund. However, if the deferral of costs in a given year would cause us to earn a greater return on common equity than authorized by the PSCW, the recovery of under-collected fuel and purchased power costs would be reduced by the amount the return exceeds the authorized amount by the PSCW. This is a possibility in any given year, and at this time, it is unknown whether this provision of the fuel rule will impact us in the current year. Climate Change The EPA began regulating greenhouse gas emissions under the Clean Air Act in January 2011 by applying the Best Available Control Technology (BACT) requirements (associated with the New Source Review program) to new and modified larger greenhouse gas emitters. Technology to remove and sequester greenhouse gas emissions is not commercially available at scale. Therefore, the EPA issued guidance that defines BACT in terms of improvements in energy efficiency as opposed to relying on pollution control equipment. In March 2012, the EPA issued a proposed rule that would impose a carbon dioxide emission rate limit on new electric generating units. The proposed limit may prevent the construction of new coal units until technology becomes commercially available. In September 2013, the EPA re-proposed rules related to emission limits on new electric generating units, and the EPA is expected to finalize them in a timely manner. In June 2014, the EPA released a proposed rule establishing greenhouse gas performance standards for existing power plants. The proposal applies to "affected electric generating units," which includes the coal-fired units at Weston and Pulliam plus the natural gas-fired Fox Energy Center. The EPA is proposing state-specific emission reduction goals. States would be required to meet an "interim goal" on average over the ten-year period from 2020 through 2029 and a "final goal" in 2030, which will achieve a nation-wide emission reduction of about 30% from 2005 levels. The EPA intends to issue final rules by June 1, 2015. State implementation plans are due by June 30, 2016, with the possibility of extensions to 2017 for a state-specific plan and to 2018 if they are using a multi-state approach. Facility compliance deadlines will be included in the final state plans.



A risk exists that any greenhouse gas legislation or regulation will increase the cost of producing energy using fossil fuels. However, we believe that capital expenditures being made at our plants are appropriate under any reasonable mandatory greenhouse gas program. We also believe that our

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future expenditures that may be required to control greenhouse gas emissions or meet renewable portfolio standards will be recoverable in rates. We will continue to monitor and manage potential risks and opportunities associated with future greenhouse gas legislative or regulatory actions. All of our generation and distribution facilities are located in the upper Midwest region of the United States. The same is true for most of our customers' facilities. The physical risks, if any, posed by climate change for these areas are not expected to be significant at this time. Ongoing evaluations will be conducted as more information on the extent of such physical changes becomes available.



Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act)

The Dodd-Frank Act was signed into law in July 2010. The final Commodity Futures Trading Commission (CFTC) rulemakings, which are essential to the Dodd-Frank Act's new framework for swaps regulation, have become effective or are becoming effective for certain companies and certain transactions. Some of the rules have not been finalized yet, are being challenged in court, or are subject to ongoing interpretations, clarifications, no-action letters, and other guidance being issued by the CFTC and its staff. As a result, it is difficult to predict how the CFTC's final Dodd-Frank Act rules will ultimately affect us. Certain provisions of the Dodd-Frank Act relating to derivatives could significantly increase our regulatory costs and/or collateral requirements, including our derivatives, which we use to hedge our commercial risks. We continue to monitor developments related to the Dodd-Frank Act rulemakings and their potential impacts on our future financial results and have implemented the applicable requirements of the Dodd-Frank Act rules that have taken effect. For example, we have addressed certain requirements applicable to transaction reporting and have implemented an internal governance structure. We have also taken the necessary steps to qualify as an end user, which provides for an exemption related to mandatory clearing. Lastly, we have made the necessary systems and process changes to comply with the rules within the CFTC's implementation timelines. CRITICAL ACCOUNTING POLICIES We have reviewed our critical accounting policies and considered whether any new critical accounting estimates or other significant changes to our accounting policies require any additional disclosures. We have found that the disclosures made in our Annual Report on Form 10-K for the year ended December 31, 2013, are still current and that there have been no significant changes. 32



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