News Column

INTEGRYS ENERGY GROUP, INC. - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

May 2, 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 diversified energy holding company with regulated natural gas and electric utility operations (serving customers in Illinois, Michigan, Minnesota, and Wisconsin), an approximate 34% equity ownership interest in ATC (a federally regulated electric transmission company), and nonregulated energy operations. RESULTS OF OPERATIONS Earnings Summary Three Months Ended March 31 Change in 2014 (Millions, except per share amounts) 2014 2013 Over 2013 Natural gas utility operations $ 99.1$ 89.7 10.5 % Electric utility operations 31.1 28.6 8.7 % Electric transmission investment 13.7 13.4 2.2 % IES's operations 10.8 51.4 (79.0 )% Holding company and other operations (2.3 )



4.4 N/A

Net income attributed to common shareholders $ 152.4 $

187.5 (18.7 )% Basic earnings per share $ 1.90$ 2.38 (20.2 )% Diluted earnings per share $ 1.89$ 2.37 (20.3 )% Average shares of common stock Basic 80.2 78.7 1.9 % Diluted 80.5 79.3 1.5 %



First Quarter 2014 Compared with First Quarter 2013

The $35.1 million decrease in our earnings was driven by:

A $28.6 million after-tax non-cash decrease in margins at IES related to

derivative and inventory fair value adjustments.

A $23.3 million after-tax increase in operating expenses at the utilities,

excluding items directly offset in margins, driven by increases in electric

utility maintenance and natural gas distribution costs. Also included in the

increase were operating costs associated with Fox Energy Center, acquired by

WPS at the end of the first quarter of 2013, which are being recovered through a rate order.



A $9.9 million after-tax decrease in natural gas utility margins due to the

quarter-over-quarter impact of the reversal in 2013 of reserves recorded in

2012 against decoupling accruals at PGL and NSG. See Note 20, Regulatory

Environment, for more information.

An $8.7 million after-tax decrease in IES's realized retail electric margins,

driven by higher purchased power and ancillary services costs related to the

colder weather.



A $6.2 million decrease in net income from discontinued operations. See Note

5, Dispositions, for more information.

These decreases were partially offset by:

The $26.3 million after-tax positive impact of rate orders at the utilities.

A $17.3 million after-tax increase in natural gas utility margins due to an

increase in sales volumes driven by colder weather, net of decoupling. Certain of our natural gas utilities did not have decoupling in 2014 to offset the impact of weather. 34



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Regulated Natural Gas Utility Segment Operations

Three Months Ended March 31 Change in 2014 (Millions, except degree days) 2014 2013 Over 2013 Revenues $ 1,272.0$ 793.9 60.2 % Purchased natural gas costs 830.4 424.1 95.8 % Margins 441.6 369.8 19.4 % Operating and maintenance expense 215.4 162.1 32.9 % Depreciation and amortization expense 36.4 32.2 13.0 % Taxes other than income taxes 10.8 9.9 9.1 % Operating income 179.0 165.6 8.1 % Miscellaneous income 0.3 0.2 50.0 % Interest expense 13.4 12.7 5.5 % Other expense (13.1 ) (12.5 ) 4.8 % Income before taxes $ 165.9 $ 153.1 8.4 % Retail throughput in therms Residential 927.2 775.9 19.5 % Commercial and industrial 301.4 236.8 27.3 % Other 23.9 20.0 19.5 % Total retail throughput in therms 1,252.5



1,032.7 21.3 %

Transport throughput in therms Residential 135.4 111.3 21.7 % Commercial and industrial 618.9 551.6 12.2 % Total transport throughput in therms 754.3 662.9 13.8 % Total throughput in therms 2,006.8 1,695.6 18.4 % Weather Average actual heating degree days 4,174 3,506 19.1 % Average normal heating degree days 3,371 3,314 1.7 % Natural gas utility margins are defined as natural gas utility operating revenues less purchased natural gas costs. 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 59% increase and an approximate 4% decrease in the average per-unit cost of natural gas sold during the first quarter of 2014 and 2013, respectively, which had no impact on margins.



First Quarter 2014 Compared with First Quarter 2013

Margins

Regulated natural gas utility segment margins increased $71.8 million, driven by:

An approximate $30 million increase in margins related to certain riders at

NSG and PGL and certain energy efficiency programs at four of our natural gas

utilities. This increase was offset by an equal increase in operating expenses, resulting in no impact on earnings. Our natural gas utilities billed approximately $18 million more to customers for energy efficiency programs at MERC, MGU, NSG, and PGL in 2014.



NSG and PGL recovered from their customers approximately $12 million more

for environmental cleanup costs at their former manufactured gas plant

sites due to an increase in sales volumes and an increase in remediation

costs, net of insurance settlements received. See Note 11, Commitments and

Contingencies, for more information about the manufactured gas plant sites.



An approximate $29 million net increase in margins due to rate orders. See

Note 20, Regulatory Environment, for more information.

The rate increases at NSG and PGL, effective June 27, 2013, but updated

effective January 1, 2014, had an approximate $30 million positive impact

on margins. The rate increase at MGU, effective January 1, 2014, resulted in an approximate $1 million positive impact on margins. 35



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The interim rate increase at MERC, effective January 1, 2014, had an approximate $1 million positive impact on margins.



Margins were negatively impacted at WPS by approximately $3 million

related to its rate order, effective January 1, 2014. The decrease in

margins was driven by the quarter-over-quarter impact of the amortization

of prior year decoupling deferrals. Rate design changes in 2014 also contributed to the decrease in margins. The new rate design includes higher fixed customer charges and lower volumetric charges, which will



reduce fluctuations in margins throughout the year caused by seasonal use.

The higher volumes sold in 2014 had less of an impact on margin as a result of the new rate design.



An approximate $12 million net increase in margins due to sales volume

variances and our decoupling mechanisms.

The combined effect of the change in weather quarter over quarter, the impact of higher weather-normalized volumes, and the impact of our decoupling mechanisms increased margins approximately $29 million. In 2014, margins at the natural gas utilities were positively impacted by colder than normal weather, net of decoupling impacts at MERC, NSG, and



PGL. Effective January 1, 2014, MGU and WPS no longer have decoupling

mechanisms in place. During the first quarter of 2014, MERC reached its

maximum accrued refund to customers under the annual 10% cap provision of

its decoupling mechanism. In 2013, decoupling mechanisms were in place for

all the natural gas utilities, but colder than normal weather had a

positive impact on MGU's margins as its decoupling mechanism did not cover

weather-related volume variances. Margins for certain customer classes in

both years were sensitive to volume variances as they were not covered by

the decoupling mechanisms. See Note 20, Regulatory Environment, for more information on our decoupling mechanisms.



Margins were negatively impacted quarter-over-quarter by approximately $17

million due to a reversal in 2013 of reserves established in 2012 against

PGL and NSG regulatory assets related to decoupling. The reversal was recorded after the Illinois Appellate Court issued an opinion in March



2013 that affirmed the ICC's order approving the decoupling mechanisms.

See Note 20, Regulatory Environment, for more information.

Operating Income

Operating income at the regulated natural gas utility segment increased $13.4 million. This increase was driven by the $71.8 million increase in margins discussed above, partially offset by a $58.4 million increase in operating expenses.

The increase in operating expenses was primarily due to:

A $17.5 million increase in energy efficiency program expenses at our natural

gas utilities. For the majority of the increase in expenses, margins increased by an equal amount, resulting in no impact on earnings.



A $12.1 million increase driven by higher amortization of regulatory assets

at certain of our natural gas utilities related to environmental cleanup

costs for manufactured gas plant sites. Margins increased by an equal amount,

resulting in no impact on earnings.

An $8.8 million increase in natural gas distribution costs, primarily at PGL.

The increase was primarily due to increased labor and external costs driven

by additional repairs and maintenance associated with the colder than normal

weather in 2014.



An $8.2 million increase in bad debt expense, driven by a cost of natural gas

component included as part of PGL's and NSG's bad debt expense tracking

mechanisms. This natural gas component is charged to customers based on

actual volumes and natural gas prices. As a result of this component, bad

debt expense was primarily impacted by both higher natural gas costs in 2014

and an increase in sales volumes. However, the increase in bad debt expense

does not impact earnings as it is offset by higher rates through a rider

mechanism, resulting in higher margins.

A $4.2 million net increase in depreciation and amortization expense.

Continued investment in property and equipment, primarily the accelerated

natural gas main replacement program at PGL, drove the increase in expense. A

$2.5 million reduction in expense in 2013 at MGU also contributed to the

quarter-over-quarter increase in expense. In January 2013, the Michigan Court

of Appeals issued an order reversing the MPSC's previously ordered

disallowance associated with the early retirement of certain MGU assets in

2010. See Note 20, Regulatory Environment, for more information.

A $1.6 million increase in asset usage charges from IBS, driven by new

software for both natural gas management and work asset management that was

placed in service during the third quarter of 2013. 36



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Regulated Electric Utility Segment Operations

Three Months Ended March 31 Change in 2014 (Millions, except degree days) 2014 2013 Over 2013 Revenues $ 349.2$ 331.8 5.2 % Fuel and purchased power costs 136.7 143.2 (4.5 )% Margins 212.5



188.6 12.7 %

Operating and maintenance expense 116.0 101.4 14.4 % Depreciation and amortization expense 25.6 21.5 19.1 % Taxes other than income taxes 12.8 12.8 - % Operating income 58.1 52.9 9.8 % Miscellaneous income 3.5 1.6 118.8 % Interest expense 11.7 9.1 28.6 % Other expense (8.2 ) (7.5 ) 9.3 % Income before taxes $ 49.9$ 45.4 9.9 % Sales in kilowatt-hours Residential 898.3 823.8 9.0 % Commercial and industrial 2,077.9 2,072.0 0.3 % Wholesale 684.8 1,046.6 (34.6 )% Other 10.6 10.7 (0.9 )% Total sales in kilowatt-hours 3,671.6 3,953.1 (7.1 )% Weather WPS: Actual heating degree days 4,515 3,803 18.7 % Normal heating degree days 3,646 3,643 0.1 % UPPCO: Actual heating degree days 4,884 4,087 19.5 % Normal heating degree days 3,972 3,967 0.1 % 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.



First Quarter 2014 Compared with First Quarter 2013

Margins

Regulated electric utility segment margins increased $23.9 million, driven by:

An approximate $15 million increase in margins related to WPS and UPPCO rate

orders effective January 1, 2014. See Note 20, Regulatory Environment, for

more information.



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

rate order resulted in an approximate $15 million increase in margins.

Although the PSCW approved an electric rate decrease, it was driven by

refunds of 2013 fuel cost over-collections and 2012 decoupling over-collections, which have no impact on margins. The increase was driven by the inclusion of the costs of operating the Fox Energy Center.



UPPCO's retail electric rate increase resulted in an approximate $2

million increase in margins. Partially offsetting these increases was an approximate $2 million



decrease in margins related to WPS fuel and purchased power costs. The

decrease was driven by fuel and purchased power cost under-collections

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

in 2013. Under the fuel rule, WPS 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. WPS's fuel and



purchased power costs that are not included in the recovery mechanism

were lower than rate case-approved amounts, resulting in a partially

offsetting increase in margins. 37



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An approximate $4 million increase in WPS's wholesale margins driven by

higher prices. Wholesale prices increased primarily due to increased generation costs.



An approximate $3 million net increase in margins from residential and

commercial and industrial customers due to variances related to sales

volumes, including the impact of decoupling. The increase was driven by

colder than normal weather in 2014. Both WPS's and UPPCO's decoupling

mechanisms were terminated effective January 1, 2014. See Note 20, Regulatory

Environment, for more information.

Operating Income

Operating income at the regulated electric utility segment increased $5.2 million. The increase was driven by the $23.9 million increase in margins discussed above, partially offset by an $18.7 million increase in operating expenses. The increase in operating expenses was driven by:

A $10.0 million increase in maintenance expense, primarily due to a major

outage at the Pulliam plant in 2014, as well as maintenance at certain WPS

generation plants.



A $4.1 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 $3.6 million increase in electric transmission expense.

A $2.9 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. Margins increased by an amount equal to the amortization, resulting in no impact on earnings.



A $1.6 million increase due to the quarter-over-quarter impact of WPS's 2013

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

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

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

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

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

Partially offsetting these increases was a $7.1 million decrease in employee benefit expenses, driven by higher discount rates assumed in 2014. In 2013, WPS deferred certain components of its pension and other employee benefit costs as a result of its 2013 PSCW rate order. WPS began amortizing this regulatory asset in 2014. The quarter-over-quarter impact of the deferral and related amortization partially offset the decrease in employee benefit expenses by $3.6 million. Other Expense Other expense increased $0.7 million, driven by an increase in interest expense due to WPS's issuance of $450.0 million of long-term debt in November 2013. The increase in interest expense was partially offset by an increase in WPS's allowance for funds used during construction, largely due to environmental compliance projects at the Columbia plant.



Electric Transmission Investment Segment Operations

Three Months Ended March 31 Change in 2014 (Millions) 2014 2013 Over 2013 Earnings from equity method investments $ 22.5 $



21.7 3.7 %

First Quarter 2014 Compared with First Quarter 2013

Earnings from Equity Method Investments

Earnings from equity method investments at the electric transmission investment segment increased $0.8 million in the first quarter of 2014. The increase resulted from higher earnings related to our approximate 34% ownership interest in ATC. Our income increases as ATC continues to increase its rate base by investing in transmission equipment and facilities for improved reliability and economic benefits for customers. 38



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IES Nonregulated Segment Operations

IES has been able to take advantage of continued growth opportunities as evidenced by increasing volumes delivered and contracted for future delivery in certain markets. During the three months ended March 31, 2014, delivered electric and natural gas volumes grew approximately 47% and 73%, respectively, compared with the same period in 2013. In addition, IES's electric and natural gas volumes for future delivery grew by approximately 13% and 76%, respectively, from March 31, 2013 to March 31, 2014. However, sustained low commodity prices, capital costs, and market volatility have led to continued competitive pressure on per-unit margins. Three Months Ended March 31 Change in 2014 (Millions, except natural gas sales volumes) 2014 2013 Over 2013 Revenues $ 1,292.2$ 545.7 136.8 % Cost of sales 1,234.8 430.7 186.7 % Margins 57.4 115.0 (50.1 )% Margin Detail Realized retail electric margins 9.4 23.9 (60.7 )% Realized renewable energy asset margins 2.6 3.0 (13.3 )% Fair value accounting adjustments 17.7 62.7 (71.8 )% Electric and renewable energy asset margins 29.7 89.6 (66.9 )% Realized retail natural gas margins 24.4 (2) 18.9 29.1 % Realized wholesale natural gas margins (1) (0.2 ) 0.2 N/A Lower-of-cost-or-market inventory adjustments 1.6 4.0 (60.0 )% Fair value accounting adjustments 1.9 2.3 (17.4 )% Natural gas margins 27.7



25.4 9.1 %

Operating and maintenance expense 36.4 32.8 11.0 % Depreciation and amortization expense 2.9 2.7 7.4 % Taxes other than income taxes 1.2 1.0 20.0 % Operating income 16.9



78.5 (78.5 )%

Earnings from equity method investments 0.1 0.2 (50.0 )% Miscellaneous income 0.3 0.4 (25.0 )% Interest expense 0.5 0.5 - % Other income (expense) (0.1 )



0.1 N/A

Income before taxes $ 16.8



$ 78.6 (78.6 )%

Physically settled volumes Retail electric sales volumes in kwh 6,356.9 4,318.2 47.2 % Wholesale assets and distributed solar electric sales volumes in kwh 14.1 18.0 (21.7 )% Retail natural gas sales volumes in bcf 87.6 50.7 72.8 % kwh - kilowatt-hours bcf - billion cubic feet



(1) Realized wholesale activity relates to remaining contracts for which

offsetting positions were entered into.

(2) This amount includes negative margins of $2.6 million related to the

amortization of the net amount paid for customer and related supply contracts in connection with acquisitions.



First Quarter 2014 Compared with First Quarter 2013

Revenues

IES's revenues increased $746.5 million. The increase was driven by higher retail sales volumes, primarily related to the expansion of the residential and small commercial customer business as well as the Compass Energy Services acquisition in May 2013. Higher average commodity prices and increased usage in 2014 related to the colder weather also contributed to the increase in revenues. 39



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Margins

IES's margins decreased $57.6 million. Significant items contributing to the change in margins were as follows:

Electric and Renewable Energy Asset Margins

Realized retail electric margins

Realized retail electric margins decreased $14.5 million. The decrease was primarily driven by an approximate $6 million increase in costs related to certain ancillary services charged by independent system operators in January 2014 due to the colder weather. In addition, sales volumes for fixed-price full requirements customers increased significantly due to the colder weather, requiring IES to purchase power at high market prices to meet this unexpected demand. Continued competitive pressure on per-unit margins also contributed to the decrease in margins.



Fair value accounting adjustments

Derivative accounting rules impact IES's margins. Fair value adjustments caused a $45.0 million decrease in electric margins quarter over quarter. These adjustments primarily relate to physical and financial contracts used to reduce price risk for supply associated with electric sales contracts. These adjustments will reverse in future periods as contracts settle.



Natural Gas Margins

Realized retail natural gas margins

Realized retail natural gas margins increased $5.5 million. The increase was primarily driven by colder weather quarter over quarter. Higher sales volumes, primarily related to the expansion of the residential and small commercial customer business as well as the Compass Energy Services acquisition in May 2013, also contributed to the increase in margins. These increases were partially offset by continued competitive pressure on per-unit margins. Realized retail natural gas margins include the amortization of customer and supply contracts related to the acquisition of Compass Energy Services.



Inventory accounting adjustments

IES's physical natural gas inventory is valued at the lower of cost or market. When the market price of natural gas is lower than the carrying value of the inventory, write-downs are recorded within margins to reflect inventory at the end of the period at its net realizable value. These write-downs result in higher margins in future periods as the inventory that was written down is sold. The $2.4 million quarter-over-quarter decrease in margins from inventory adjustments was driven by a lower volume of inventory withdrawn from storage for which write-downs had previously been recorded.



Operating Income

IES's operating income decreased $61.6 million. The main driver of the decrease was the $57.6 million decrease in margins discussed above. In addition, operating expenses increased $4.0 million. The increase in operating expenses was primarily driven by an increase in costs related to the Compass Energy Services acquisition in May 2013, as well as the expansion of the residential and small commercial customer business.



Holding Company and Other Segment Operations

Three Months Ended March 31 (Millions) 2014 2013 Change in 2014 Over 2013 Operating loss $ (0.8 )$ (3.9 ) (79.5 )% Other expense (11.3 ) (3.1 ) 264.5 % Loss before taxes $ (12.1 )$ (7.0 ) 72.9 %



First Quarter 2014 Compared with First Quarter 2013

Operating Loss

Operating loss at the holding company and other segment decreased $3.1 million. The decrease was primarily driven by a $1.6 million decrease in operating losses at ITF. Other Expense Other expense at the holding company and other segment increased $8.2 million. The increase was primarily due to a $6.4 million increase in interest expense on long-term debt, driven by the issuance of $400.0 million of Junior Subordinated Notes during August 2013. Also contributing to 40



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the increase was the $2.1 million quarter-over-quarter negative impact of excise tax credits recorded at ITF in 2013 as a result of the American Taxpayer Relief Act of 2012. These excise tax credits were not available in 2014.



Provision for Income Taxes

Three Months Ended March 31 2014 2013 Effective tax rate 37.0 % 37.6 % There was no material change in our effective tax rate quarter over quarter. Discontinued Operations Three Months Ended March 31 Change in 2014 Over (Millions) 2014 2013 2013 Discontinued operations, net of tax $ (0.1 ) $ 6.1 N/A



First Quarter 2014 Compared with First Quarter 2013

Earnings from discontinued operations, net of tax, decreased $6.2 million in 2014. In the first quarter of 2013, we remeasured uncertain tax positions included in our liability for unrecognized tax benefits after effectively settling a certain state income tax examination. We reduced the provision for income taxes related to this remeasurement, of which the majority was reported as discontinued operations. 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 equity and 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 three months ended March 31, 2014, net cash provided by operating activities was $263.3 million, compared with $319.6 million during the same quarter in 2013. The $56.3 million decrease in net cash provided by operating activities was driven by:



An $882.8 million decrease in cash related to higher costs of natural gas,

fuel, and purchased power in 2014. The decrease was driven by higher energy

prices and colder than normal weather in the first quarter of 2014. Of this

variance, $170.6 million relates to under-collections from regulated utility

customers. These under-collections were higher in 2014 than in 2013. To meet

the higher energy needs of customers, we purchased natural gas, fuel, and

purchased power at higher prices than expected in 2014, which were not yet

reflected in the rates charged to our customers.

A $73.8 million decrease in cash related to increased operating and

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

utility maintenance, natural gas distribution costs, and operating costs

associated with the Fox Energy Center, which was acquired by WPS at the end

of the first quarter of 2013.

A $52.4 million decrease in cash driven by higher collateral requirements in

2014 compared with 2013 at IES. Collateral requirements are based on forward

natural gas and electricity prices and forward positions with counterparties.

An $8.6 million increase in cash paid for interest, primarily driven by an

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

A $5.4 million increase in contributions to pension and other postretirement

benefit plans.



These decreases in cash were partially offset by:

An $830.7 million increase in cash collections from customers, mainly due to

rate increases at the regulated utilities and the colder than normal weather

in 2014.



A $61.7 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.



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

for WPS's early termination of a tolling agreement in connection with the

purchase of Fox Energy Company LLC. 41



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A $17.6 million increase in cash related to customer prepayments and credit

balances. In the first quarter of 2013, cash received in relation to amounts

billed was lower because customer prepayments had grown during an unusually

warm 2012. Investing Cash Flows During the three months ended March 31, 2014, net cash used for investing activities was $163.3 million, compared with $473.2 million during the same quarter in 2013. The $309.9 million decrease in net cash used for investing activities was primarily due to $391.6 million of cash used in 2013 for WPS's purchase of Fox Energy Company LLC. See Note 4, Acquisitions, for more information regarding this purchase. Partially offsetting the decrease in net cash used was the quarter-over-quarter negative impact of the receipt of a $69.0 million Section 1603 Grant for the Crane Creek wind project in 2013 and a $12.6 million increase in cash used for other capital expenditures (discussed below).



Capital Expenditures

Capital expenditures by business segment for the three months ended March 31 were as follows: Reportable Segment (millions) 2014 2013 Change Natural gas utility $ 68.2$ 85.8$ (17.6 ) Electric utility 55.7 439.9 (384.2 ) IES 7.5 3.4 4.1 Holding company and other 28.2 9.5 18.7



Integrys Energy Group consolidated $ 159.6$ 538.6$ (379.0 )

The decrease in capital expenditures at the natural gas utility segment in 2014 compared with 2013 was primarily due to colder weather conditions impacting work on the accelerated natural gas main replacement program at PGL. The decrease in capital expenditures at the electric utility segment in 2014 compared with 2013 was primarily due to WPS's 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. Finally, capital expenditures at the holding company and other segment increased in 2014 compared with 2013, primarily due to increased expenditures for software projects and office leasehold improvements.



Financing Cash Flows

During the three months ended March 31, 2014, net cash used for financing activities was $72.1 million, compared with net cash provided by financing activities of $197.2 million during the same quarter in 2013. The $269.3 million quarter-over-quarter change was driven by:

A $200.0 million decrease in borrowings under WPS's term credit facility,

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

Company LLC.



A $78.1 million decrease in cash due to $4.1 million of net repayments of

commercial paper in 2014, compared with $74.0 million of net borrowings of

commercial paper in 2013.

A $7.8 million increase in cash used to purchase shares of our common stock

on the open market to satisfy requirements of our Stock Investment Plan and

certain stock-based employee benefit and compensation plans. We began

purchasing shares of our common stock on the open market starting in February

2014 as well as during a short period during the first quarter of 2013.

These decreases in cash were partially offset by the quarter-over-quarter impact of a $22.0 million repayment of long-term debt in 2013.

Significant Financing Activities

The following table provides a summary of common stock activity to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans: Period

Method of meeting requirements



Beginning 02/05/2014 Purchasing shares on the open market 02/05/2013 - 02/05/2014 Issued new shares 01/01/2012 - 02/04/2013 Purchased shares on the open market

For information on short-term debt, see Note 9, Short-Term Debt and Lines of Credit.

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There were no significant changes in long-term debt during the first quarter of 2014.

Credit Ratings Our current credit ratings and the credit ratings for WPS, PGL, and NSG are listed in the table below: Credit Ratings Standard & Poor's Moody's Integrys Energy Group Issuer credit rating A- N/A Senior unsecured debt BBB+ Baa1 Commercial paper A-2 P-2 Junior subordinated notes BBB Baa2 WPS 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 PGL Issuer credit rating A- A2 Senior secured debt A Aa3 Commercial paper A-2 P-1 NSG Issuer credit rating A- A2 Senior secured debt A Aa3



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

On January 31, 2014, Moody's confirmed the credit ratings for Integrys Energy Group and raised the credit ratings for WPS, PGL, and NSG. The issuer rating was raised to "A1" from "A2" for WPS and to "A2" from "A3" for both PGL and NSG. WPS's first mortgage bonds rating was raised to "Aa2" from "Aa3." The senior secured debt rating was raised to "Aa2" from "Aa3" for WPS and to "Aa3" from "A1" for both PGL and NSG. The preferred stock rating for WPS was raised to "A3" from "Baa1." Finally, PGL's commercial paper rating was raised to "P-1" from "P-2." The upgrade in ratings of the utilities reflects Moody's views of the regulatory provisions in Wisconsin and Illinois that are consistent with a generally improving regulatory environment for electric and natural gas utilities in the United States.



Discontinued Operations

These cash flows primarily relate to the operations of WPS Beaver Falls Generation, LLC, WPS Syracuse Generation, LLC, and Combined Locks Energy Center, LLC. See Item 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations, Discontinued Operations, and Note 5, Dispositions, for more information. 43

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Future Capital Requirements and Resources

Contractual Obligations

The following table shows our contractual obligations as of March 31, 2014, including those of our subsidiaries:

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) $ 7,322.0$ 209.6$ 506.0$ 382.1$ 6,224.3 Operating lease obligations 92.4 4.9 13.1 15.0 59.4 Energy and transportation purchase obligations (2) 2,407.2 611.4 671.9 321.7 802.2 Purchase orders (3) 1,163.3 1,028.0 124.9 3.1 7.3 Capital contributions to equity method investment 5.1 5.1 - - - Pension and other postretirement funding obligations (4) 48.2 15.6 32.6 - - Uncertain tax positions 0.7 0.7 - - - Total contractual cash obligations $ 11,038.9$ 1,875.3$ 1,348.5$ 721.9$ 7,093.2



(1) Represents bonds and notes issued, as well as loans made to us and our

subsidiaries. We record all principal obligations on the balance sheet. For

purposes of this table, it is assumed that the current interest rates on

variable rate debt will remain in effect until the debt matures.

(2) Energy and related commodity supply contracts at IES included as part of

energy and transportation purchase obligations are primarily entered into to

meet future obligations to deliver energy and related products to customers;

therefore, these costs will be recovered as customer sales contracts settle.

The utility subsidiaries expect to recover the costs of their contracts 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 $588.2 million at March 31, 2014, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 11, Commitments and Contingencies, for more information about environmental liabilities. The table also does not reflect estimated future payments for the March 31, 2014 liability of $1.6 million related to unrecognized tax benefits, as the amount and timing of payments are uncertain. See Note 10, Income Taxes, for more information about unrecognized tax benefits. Capital Requirements



Projected capital expenditures by segment for 2014 through 2016, including amounts expended through March 31, 2014, are as follows: (Millions)

2014 2015 2016 Total Natural Gas Utility Distribution and transmission projects and underground storage facilities $ 556$ 478$ 481$ 1,515 Other projects 30 34 23 87 Electric Utility (1) Distribution and energy supply operations projects 139 137 131 407 Environmental projects (2) 140 135 105 380 Other projects 18 21 167 206 IES Renewable energy and other projects 68 42



42 152

Holding Company and Other Corporate or shared services software and infrastructure projects 68 31 40 139 Compressed natural gas fueling stations 32 44 45 121 Repairs and safety measures at nonutility hydroelectric facilities (1) - - 1 1 Total capital expenditures $ 1,051$ 922$ 1,035$ 3,008



(1) Approximately $31 million of projected capital expenditures relates to

UPPCO. See Note 5, Dispositions, for more information on the pending sale

of UPPCO.



(2) This primarily relates to the installation of ReACTTM emission control

technology at Weston 3 and the installation of scrubbers at the Columbia

plant.



We expect to provide capital contributions to ATC (not included in the above table) of approximately $56 million from 2014 through 2016.

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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, acquisition and development opportunities, 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), dividends from our subsidiaries, and debt and equity financings. We plan to keep debt to equity ratios at levels that can support current credit ratings and corporate growth.



Under an existing shelf registration statement, we may issue debt, equity, certain types of hybrid securities, and other financial instruments with amounts, prices, and terms to be determined at the time of future offerings.

WPS currently has two shelf registration statements. Under these registration statements, WPS 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 March 31, 2014, we and each of our subsidiaries 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. Various laws, regulations, and financial covenants impose restrictions on the ability of certain of our regulated utility subsidiaries to transfer funds to us in the form of dividends. Our regulated utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly. Although these restrictions limit the amount of funding the various operating subsidiaries can provide to us, management does not believe these restrictions will have a significant impact on our ability to access cash for payment of dividends on common stock or other future funding obligations. See Note 15, Common Equity, for more information on dividend restrictions.



Other Future Considerations

Presque Isle System Support Resources (SSR) Costs

In August 2013, Wisconsin Electric Power Company (Wisconsin Electric) submitted to MISO a notice, in which Wisconsin Electric 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 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 by allocating the SSR costs associated with the operation of the Presque Isle units to regulated and nonregulated load serving entities, including WPS, UPPCO, and IES, based on load ratio share within the ATC footprint. In January 2014, MISO submitted a new rate schedule to the FERC reflecting this. The allocated SSR costs for WPS are estimated at $9 million annually, which could change based on a filing by the PSCW to the FERC in April 2014 to change the allocation methodology to the various parties. In April 2013, the PSCW ordered that SSR costs for WPS retail customers should be deferred until December 31, 2015. At that time, the PSCW will determine the appropriate ratemaking treatment. SSR costs for Michigan customers, including UPPCO and WPS, will be recovered from customers through the Power Supply Cost Recovery mechanism. Allocated SSR costs for IES can be passed through to customers.



MISO Transmission Owner Return on Equity Complaint

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to, among other things, reduce the base return on equity used by MISO transmission owners, including ATC, to 9.15%. ATC's current authorized return on equity is 12.2%. 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 and resulting changes to our financial condition and results of operations.



Wisconsin Fuel Rule Under-collection "Cap"

WPS uses a "fuel window" mechanism to recover fuel and purchased power costs for its 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 WPS 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 that authorized 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 WPS in the current year. 45



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Table of Contents Decoupling In 2012, the Illinois Attorney General and Citizens Utility Board appealed the ICC's authority to approve PGL's and NSG's permanent decoupling mechanism. As a result, revenues collected under this mechanism were potentially subject to refund. In 2012, PGL and NSG established offsetting reserves equal to decoupling amounts accrued. In March 2013, the Illinois Appellate Court affirmed the ICC's authority to approve the permanent decoupling mechanism. Therefore, the reserves recorded in 2012 were reversed in the first quarter of 2013. In June 2013, the Illinois Attorney General and Citizens Utility Board petitioned the Illinois Supreme Court to review the Court's decision. The Illinois Supreme Court granted the request in September 2013, and briefing is in progress. The Illinois Supreme Court has no deadline by which it must act. Decoupling amounts recorded in 2012 were fully recovered and amounts in 2013 will be refunded to customers in 2014. Decoupling amounts in 2014 will continue to be accrued, absent an adverse Illinois Supreme Court decision.



See Note 20, Regulatory Environment, for more information on all of our subsidiaries' decoupling mechanisms.

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. The EPA was also directed to propose a rule for existing units by no later than June 1, 2014, and issue a final rule by June 1, 2015, with state implementation plans due by June 30, 2016. 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 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. The majority 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 this area 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. 46



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