10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

[X]      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2013

OR

[ ]      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 

For the transition period from __________ to __________

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification No.
1-11337	INTEGRYS ENERGY GROUP, INC. (A Wisconsin Corporation) 130 East Randolph Street Chicago, IL 60601-6207 (312) 228-5400	39-1775292

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes [X]    No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes [X]    No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer [X]            Accelerated filer [ ]

Non-accelerated filer [ ]            Smaller reporting company [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes [ ]    No [X]

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Common stock, $1 par value,

79,128,089 shares outstanding at

April 26, 2013

INTEGRYS ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2013

TABLE OF CONTENTS

				Page
	Forward-Looking Statements			1
PART I.	FINANCIAL INFORMATION			2
Item 1.	Financial Statements (Unaudited)			2
	Condensed Consolidated Statements of Income			2
	Condensed Consolidated Statements of Comprehensive Income			3
	Condensed Consolidated Balance Sheets			4
	Condensed Consolidated Statements of Cash Flows			5
	Condensed Notes to Financial Statements			6
			Page
	Note 1	Financial Information	6
	Note 2	Cash and Cash Equivalents	6
	Note 3	Risk Management Activities	7
	Note 4	Acquisitions	10
	Note 5	Discontinued Operations	11
	Note 6	Investment in ATC	13
	Note 7	Inventories	14
	Note 8	Goodwill and Other Intangible Assets	14
	Note 9	Short-Term Debt and Lines of Credit	15
	Note 10	Long-Term Debt	16
	Note 11	Income Taxes	17
	Note 12	Commitments and Contingencies	17
	Note 13	Guarantees	20
	Note 14	Employee Benefit Plans	21
	Note 15	Stock-Based Compensation	21
	Note 16	Common Equity	23
	Note 17	Accumulated Other Comprehensive Loss	25
	Note 18	Variable Interest Entities	26
	Note 19	Fair Value	27
	Note 20	Advertising Costs	30
	Note 21	Regulatory Environment	30
	Note 22	Segments of Business	32
	Note 23	New Accounting Pronouncements	33
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			35
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk			48
ITEM 4.	Controls and Procedures			49
PART II.	OTHER INFORMATION			50
ITEM 1.	Legal Proceedings			50
ITEM 1A.	Risk Factors			50
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds			50
ITEM 6.	Exhibits			50
Signature				51
EXHIBIT INDEX				52

i

Acronyms Used in this Quarterly Report on Form 10-Q

AFUDC	Allowance for Funds Used During Construction
AMRP	Accelerated Natural Gas Main Replacement Program
ASC	Accounting Standards Codification
ATC	American Transmission Company LLC
EPA	United States Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	United States Generally Accepted Accounting Principles
IBS	Integrys Business Support, LLC
ICC	Illinois Commerce Commission
IRS	United States Internal Revenue Service
ITF	Integrys Transportation Fuels, LLC (doing business as Trillium CNG)
LIFO	Last-in, First-out
MERC	Minnesota Energy Resources Corporation
MGU	Michigan Gas Utilities Corporation
MISO	Midwest Independent Transmission System Operator, Inc.
MPSC	Michigan Public Service Commission
MPUC	Minnesota Public Utilities Commission
N/A	Not Applicable
NSG	North Shore Gas Company
OCI	Other Comprehensive Income
PELLC	Peoples Energy, LLC (formerly known as Peoples Energy Corporation)
PGL	The Peoples Gas Light and Coke Company
PSCW	Public Service Commission of Wisconsin
SEC	United States Securities and Exchange Commission
UPPCO	Upper Peninsula Power Company
WDNR	Wisconsin Department of Natural Resources
WPS	Wisconsin Public Service Corporation

ii

Forward-Looking Statements

In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are not guarantees of future results and conditions. Although we believe that these forward-looking statements and the underlying assumptions are reasonable, we cannot provide assurance that such statements will prove correct.

Forward-looking statements involve a number of risks and uncertainties. Some risks that could cause actual results to differ materially from those expressed or implied in forward-looking statements include those described in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2012, as may be amended or supplemented in Part II, Item 1A of our subsequently filed Quarterly Reports on Form 10-Q (including this report), and those identified below:

• The timing and resolution of rate cases and related negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated businesses;

• Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards;

• Other federal and state legislative and regulatory changes, including deregulation and restructuring of the electric and natural gas utility industries, financial reform, health care reform, energy efficiency mandates, reliability standards, pipeline integrity and safety standards, and changes in tax and other laws and regulations to which we and our subsidiaries are subject;

• Costs and effects of litigation and administrative proceedings, settlements, investigations, and claims;

• Changes in credit ratings and interest rates caused by volatility in the financial markets and actions of rating agencies and their impact on our and our subsidiaries’ liquidity and financing efforts;

• The risks associated with changing commodity prices, particularly natural gas and electricity, and the available sources of fuel, natural gas, and purchased power, including their impact on margins, working capital, and liquidity requirements;

• The timing and outcome of any audits, disputes, and other proceedings related to taxes;

• The effects, extent, and timing of additional competition or regulation in the markets in which our subsidiaries operate;

• The ability to retain market-based rate authority;

• The risk associated with the value of goodwill or other intangible assets and their possible impairment;

• The investment performance of employee benefit plan assets and related actuarial assumptions, which impact future funding requirements;

• The impact of unplanned facility outages;

• Changes in technology, particularly with respect to new, developing, or alternative sources of generation;

• The effects of political developments, as well as changes in economic conditions and the related impact on customer use, customer growth, and our ability to adequately forecast energy use for our customers;

• Potential business strategies, including mergers, acquisitions, and construction or disposition of assets or businesses, which cannot be assured to be completed timely or within budgets;

• The risk of terrorism or cyber security attacks, including the associated costs to protect our assets and respond to such events;

• The risk of failure to maintain the security of personally identifiable information, including the associated costs to notify affected persons and to mitigate their information security concerns;

• The effectiveness of risk management strategies, the use of financial and derivative instruments, and the related recovery of these costs from customers in rates;

• The risk of financial loss, including increases in bad debt expense, associated with the inability of our and our subsidiaries’ counterparties, affiliates, and customers to meet their obligations;

• Unusual weather and other natural phenomena, including related economic, operational, and/or other ancillary effects of any such events;

• The ability to use tax credit and loss carryforwards;

• The financial performance of ATC and its corresponding contribution to our earnings;

• The effect of accounting pronouncements issued periodically by standard-setting bodies; and

• Other factors discussed elsewhere herein and in other reports we file with the SEC.

Except to the extent required by the federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

1

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements

INTEGRYS ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)	Three Months Ended
	March 31
(Millions, except per share data)	2013			2012
Utility revenues	$	1,123.8		$	971.0
Nonregulated revenues	554.4			276.9
Total revenues	1,678.2			1,247.9
Utility cost of fuel, natural gas, and purchased power	565.1			472.3
Nonregulated cost of sales	436.8			273.7
Operating and maintenance expense	295.1			259.3
Depreciation and amortization expense	60.9			62.1
Taxes other than income taxes	27.2			27.4
Operating income	293.1			153.1
Earnings from equity method investments	22.3			21.1
Miscellaneous income	5.7			2.4
Interest expense	(29.3		)	(30.4		)
Other expense	(1.3		)	(6.9		)
Income before taxes	291.8			146.2
Provision for income taxes	109.6			47.4
Net income from continuing operations	182.2			98.8
Discontinued operations, net of tax	6.1			0.9
Net income	188.3			99.7
Preferred stock dividends of subsidiary	(0.8		)	(0.8		)
Net income attributed to common shareholders	$	187.5		$	98.9
Average shares of common stock
Basic	78.7			78.6
Diluted	79.3			79.2
Earnings per common share (basic)
Net income from continuing operations	$	2.30		$	1.25
Discontinued operations, net of tax	0.08			0.01
Earnings per common share (basic)	$	2.38		$	1.26
Earnings per common share (diluted)
Net income from continuing operations	$	2.29		$	1.24
Discontinued operations, net of tax	0.08			0.01
Earnings per common share (diluted)	$	2.37		$	1.25
Dividends per common share declared	$	0.68		$	0.68

The accompanying condensed notes are an integral part of these statements.

2

INTEGRYS ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)	Three Months Ended
	March 31
(Millions)	2013			2012
Net income	$	188.3		$	99.7
Other comprehensive income, net of tax:
Cash flow hedges
Unrealized net gains (losses) arising during period, net of tax of $ – million and $(0.2) million, respectively	0.1			(0.3		)
Reclassification of net losses to net income, net of tax of $0.6 million and $1.0 million, respectively	0.9			1.5
Cash flow hedges, net	1.0			1.2
Defined benefit pension plans
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.4 million and $0.3 million, respectively	0.6			0.3
Other comprehensive income, net of tax	1.6			1.5
Comprehensive income	189.9			101.2
Preferred stock dividends of subsidiary	(0.8		)	(0.8		)
Comprehensive income attributed to common shareholders	$	189.1		$	100.4

The accompanying condensed notes are an integral part of these statements. 

3

INTEGRYS ENERGY GROUP, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)	March 31			December 31
(Millions)	2013			2012
Assets
Cash and cash equivalents	$	72.0		$	27.4
Collateral on deposit	25.4			41.0
Accounts receivable and accrued unbilled revenues, net of reserves of $47.2 and $43.5, respectively	899.0			796.8
Inventories	140.2			271.9
Assets from risk management activities	182.5			145.4
Regulatory assets	88.4			110.8
Assets held for sale	2.5			10.1
Deferred income taxes	42.8			64.3
Prepaid taxes	116.6			152.8
Other current assets	31.3			38.6
Current assets	1,600.7			1,659.1
Property, plant, and equipment, net of accumulated depreciation of $3,225.5 and $3,114.7, respectively	5,941.8			5,501.9
Regulatory assets	1,842.7			1,813.8
Assets from risk management activities	50.3			45.3
Equity method investments	518.3			512.2
Goodwill	658.3			658.3
Other long-term assets	152.3			136.8
Total assets	$	10,764.4		$	10,327.4
Liabilities and Equity
Short-term debt	$	756.4		$	482.4
Current portion of long-term debt	291.5			313.5
Accounts payable	450.1			457.7
Liabilities from risk management activities	140.9			181.9
Accrued taxes	95.9			83.0
Regulatory liabilities	84.8			65.6
Liabilities held for sale	—			0.2
Other current liabilities	287.1			229.0
Current liabilities	2,106.7			1,813.3
Long-term debt	1,931.7			1,931.7
Deferred income taxes	1,263.9			1,203.8
Deferred investment tax credits	48.9			49.3
Regulatory liabilities	377.6			370.5
Environmental remediation liabilities	641.2			651.5
Pension and other postretirement benefit obligations	566.4			625.2
Liabilities from risk management activities	49.3			58.4
Asset retirement obligations	416.3			411.2
Other long-term liabilities	138.3			135.7
Long-term liabilities	5,433.6			5,437.3
Commitments and contingencies
Common stock – $1 par value; 200,000,000 shares authorized; 78,809,948 shares issued; 78,353,096 shares outstanding	78.8			78.3
Additional paid-in capital	2,590.2			2,574.6
Retained earnings	565.4			431.5
Accumulated other comprehensive loss	(39.3		)	(40.9		)
Shares in deferred compensation trust	(22.0		)	(17.7		)
Total common shareholders’ equity	3,173.1			3,025.8
Preferred stock of subsidiary – $100 par value; 1,000,000 shares authorized; 511,882 shares issued; 510,495 shares outstanding	51.1			51.1
Noncontrolling interest in subsidiaries	(0.1		)	(0.1		)
Total liabilities and equity	$	10,764.4		$	10,327.4

The accompanying condensed notes are an integral part of these statements. 

4

INTEGRYS ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Three Months Ended
	March 31
(Millions)	2013			2012
Operating Activities
Net income	$	188.3		$	99.7
Adjustments to reconcile net income to net cash provided by operating activities
Discontinued operations, net of tax	(6.1		)	(0.9		)
Depreciation and amortization expense	60.9			62.1
Recoveries and refunds of regulatory assets and liabilities	16.5			9.5
Net unrealized (gains) losses on energy contracts	(65.2		)	43.7
Bad debt expense	9.3			10.1
Pension and other postretirement expense	15.9			17.5
Pension and other postretirement contributions	(63.2		)	(246.2		)
Deferred income taxes and investment tax credits	68.3			29.7
Equity income, net of dividends	(4.4		)	(3.8		)
Termination of tolling agreement with Fox Energy Company LLC	(50.0		)	—
Other	6.3			2.7
Changes in working capital
Collateral on deposit	15.4			(13.7		)
Accounts receivable and accrued unbilled revenues	(182.8		)	49.8
Inventories	137.9			133.0
Other current assets	45.4			54.6
Accounts payable	24.7			(77.7		)
Temporary LIFO liquidation credit	83.2			36.7
Other current liabilities	19.2			18.0
Net cash provided by operating activities	319.6			224.8
Investing Activities
Capital expenditures	(147.0		)	(123.0		)
Proceeds from the sale or disposal of assets	1.1			1.4
Capital contributions to equity method investments	(1.7		)	(10.4		)
Acquisition of Fox Energy Company LLC	(391.6		)	—
Grant received related to Crane Creek Wind Project	69.0			—
Other	(3.0		)	(4.6		)
Net cash used for investing activities	(473.2		)	(136.6		)
Financing Activities
Short-term debt, net	74.0			2.2
Borrowing on term credit facility	200.0			—
Repayment of long-term debt	(22.0		)	—
Proceeds from stock option exercises	6.4			10.1
Shares purchased for stock-based compensation	(2.0		)	(24.6		)
Payment of dividends
Preferred stock of subsidiary	(0.8		)	(0.8		)
Common stock	(50.1		)	(53.0		)
Payments made on derivative contracts related to divestitures classified as financing activities	(3.8		)	(9.0		)
Other	(4.5		)	0.2
Net cash provided by (used for) financing activities	197.2			(74.9		)
Change in cash and cash equivalents – continuing operations	43.6			13.3
Change in cash and cash equivalents – discontinued operations
Net cash (used for) provided by operating activities	(0.6		)	1.0
Net cash provided by (used for) investing activities	1.6			(0.1		)
Net change in cash and cash equivalents	44.6			14.2
Cash and cash equivalents at beginning of period	27.4			28.1
Cash and cash equivalents at end of period	$	72.0		$	42.3

The accompanying condensed notes are an integral part of these statements.

5

INTEGRYS ENERGY GROUP, INC. AND SUBSIDIARIES

CONDENSED NOTES TO FINANCIAL STATEMENTS

March 31, 2013

NOTE 1 — FINANCIAL INFORMATION

As used in these notes, the term “financial statements” refers to the condensed consolidated financial statements. This includes the condensed consolidated statements of income, condensed consolidated statements of comprehensive income, condensed consolidated balance sheets, and condensed consolidated statements of cash flows, unless otherwise noted. In this report, when we refer to “us,” “we,” “our,” or “ours,” we are referring to Integrys Energy Group, Inc.

We prepare our financial statements in conformity with the rules and regulations of the SEC for Quarterly Reports on Form 10-Q and in accordance with GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2012.

In management’s opinion, these unaudited financial statements include all adjustments necessary for a fair presentation of financial results. All adjustments are normal and recurring, unless otherwise noted. All intercompany transactions have been eliminated in consolidation. Financial results for an interim period may not give a true indication of results for the year.

NOTE 2 — CASH AND CASH EQUIVALENTS

Short-term investments with an original maturity of three months or less are reported as cash equivalents.

The following is a supplemental disclosure to our statements of cash flows:

	Three Months Ended March 31
(Millions)	2013			2012
Cash paid for interest	$	4.8		$	8.9
Cash received for income taxes	(1.0		)	(33.2		)

Cash received for income taxes decreased $32.2 million primarily due to refunds received in 2012 related to prior year amended tax returns.

Significant noncash transactions were:

	Three Months Ended March 31
(Millions)	2013		2012
Construction costs funded through accounts payable	$	59.8	$	50.2
Equity issued for stock-based compensation plans	18.7		—
Equity issued for reinvested dividends	3.0		—
Risk management asset related to sale of Beaver Falls and Syracuse *	6.8		—

* See Note 5, "Discontinued Operations," for more information.

6

NOTE 3 — RISK MANAGEMENT ACTIVITIES

The following tables show our assets and liabilities from risk management activities:

		March 31, 2013
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Utility Segments
Nonhedge derivatives
Natural gas contracts	Current	$	9.8	$	3.7
Natural gas contracts	Long-term	1.9		—
Financial transmission rights (FTRs)	Current	1.0		0.1
Petroleum product contracts	Current	0.1		—
Coal contracts	Current	0.1		2.8
Coal contracts	Long-term	—		2.0
Cash flow hedges
Natural gas contracts	Current	—		0.1
Nonregulated Segments
Nonhedge derivatives
Natural gas contracts	Current	24.3		19.7
Natural gas contracts	Long-term	10.0		5.3
Electric contracts	Current	147.2		114.5
Electric contracts	Long-term	38.4		42.0
	Current	182.5		140.9
	Long-term	50.3		49.3
Total		$	232.8	$	190.2

*   We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

		December 31, 2012
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Utility Segments
Nonhedge derivatives
Natural gas contracts	Current	$	2.5	$	14.0
Natural gas contracts	Long-term	0.9		0.8
FTRs	Current	2.1		0.1
Petroleum product contracts	Current	0.2		—
Coal contracts	Current	0.3		4.7
Coal contracts	Long-term	2.2		4.3
Cash flow hedges
Natural gas contracts	Current	—		0.4
Nonregulated Segments
Nonhedge derivatives
Natural gas contracts	Current	51.7		48.5
Natural gas contracts	Long-term	11.5		7.6
Electric contracts	Current	88.6		114.2
Electric contracts	Long-term	30.7		45.7
	Current	145.4		181.9
	Long-term	45.3		58.4
Total		$	190.7	$	240.3

*   We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

7

The following tables show the potential effect of netting arrangements on our financial position for recognized derivative assets and liabilities:

	March 31, 2013
(Millions)	Gross Amount		Gross Amount Not Offset in the Balance Sheet, including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements
Utility Segments	$	12.8	$	3.4	$	9.4
Nonregulated Segments	219.7		160.3		59.4
Total	232.5		163.7		68.8
Derivative assets not subject to master netting or similar arrangements	0.3				0.3
Total risk management assets	$	232.8			$	69.1
Derivative liabilities subject to master netting or similar arrangements
Utility Segments	$	3.9	$	3.4	$	0.5
Nonregulated Segments	181.4		160.3		21.1
Total	185.3		163.7		21.6
Derivative liabilities not subject to master netting or similar arrangements	4.9				4.9
Total risk management liabilities	$	190.2			$	26.5

	December 31, 2012
(Millions)	Gross Amount		Gross Amount Not Offset in the Balance Sheet, including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements
Utility Segments	$	5.7	$	3.0	$	2.7
Nonregulated Segments	182.5		145.4		37.1
Total	188.2		148.4		39.8
Derivative assets not subject to master netting or similar arrangements	2.5				2.5
Total risk management assets	$	190.7			$	42.3
Derivative liabilities subject to master netting or similar arrangements
Utility Segments	$	15.3	$	3.8	$	11.5
Nonregulated Segments	215.4		159.8		55.6
Total	230.7		163.6		67.1
Derivative liabilities not subject to master netting or similar arrangements	9.6				9.6
Total risk management liabilities	$	240.3			$	76.7

Our master netting and similar arrangements have conditional rights of setoff that can be enforced under a variety of situations, including counterparty default or credit rating downgrade below investment grade. Financial collateral received or provided is restricted to the extent that is it required per the terms of the related agreements. We have trade receivables and trade payables, subject to master netting or similar arrangements, that are not included in the above table. These amounts may offset (or conditionally offset) the net amounts presented in the above table. The net amounts in the above table represent the netting of fair value balances under master netting or similar arrangements, and the netting of cash collateral, as applicable.

The following table shows our cash collateral positions:

(Millions)	March 31, 2013		December 31, 2012
Cash collateral provided to others:
Related to contracts under master netting or similar arrangements	$	24.3	$	39.9
Other	1.1		1.1
Cash collateral received from others related to contracts under master netting or similar arrangements *	—		0.2

*   Reflected in other current liabilities on the balance sheets.

8

Certain of our derivative and nonderivative commodity instruments contain provisions that could require “adequate assurance” in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The following table shows the aggregate fair value of all derivative instruments with specific credit risk related contingent features that were in a liability position:

(Millions)	March 31, 2013		December 31, 2012
Integrys Energy Services	$	67.2	$	108.9
Utility segments	3.8		14.0

If all of the credit risk related contingent features contained in commodity instruments (including derivatives, nonderivatives, normal purchase and normal sales contracts, and applicable payables and receivables) had been triggered, our collateral requirement would have been as follows:

(Millions)	March 31, 2013		December 31, 2012
Collateral that would have been required:
Integrys Energy Services	$	124.6	$	173.8
Utility segments	0.4		10.1
Collateral already satisfied:
Integrys Energy Services — Letters of credit	3.2		3.2
Collateral remaining:
Integrys Energy Services	121.4		170.6
Utility segments	0.4		10.1

Utility Segments

Non-Hedge Derivatives

Utility derivatives include natural gas purchase contracts, coal purchase contracts, financial derivative contracts (futures, options, and swaps), and FTRs used to manage electric transmission congestion costs. Both the electric and natural gas utility segments use futures, options, and swaps to manage the risks associated with the market price volatility of natural gas supply costs, and the costs of gasoline and diesel fuel used by utility vehicles. The electric utility segment also uses oil futures and options to manage price risk related to coal transportation.

The utilities had the following notional volumes of outstanding nonhedge derivative contracts:

	March 31, 2013			December 31, 2012
	Purchases	Sales	Other Transactions	Purchases	Sales	Other Transactions
Natural gas (millions of therms)	595.4	—	N/A	1,072.6	0.1	N/A
FTRs (millions of kilowatt-hours)	N/A	N/A	1,579.0	N/A	N/A	4,057.2
Petroleum products (barrels)	50,855.0	N/A	N/A	62,811.0	N/A	N/A
Coal contracts (millions of tons)	4.7	0.2	N/A	5.1	N/A	N/A

The table below shows the unrealized gains (losses) recorded related to nonhedge derivatives at the utilities:

		Three Months Ended March 31
(Millions)	Financial Statement Presentation	2013			2012
Natural gas contracts	Balance Sheet — Regulatory assets (current)	$	13.0		$	(6.4	)
Natural gas contracts	Balance Sheet — Regulatory assets (long-term)	0.8			(0.8		)
Natural gas contracts	Balance Sheet — Regulatory liabilities (current)	5.9			(3.7		)
Natural gas contracts	Balance Sheet — Regulatory liabilities (long-term)	0.8			0.1
Natural gas contracts	Income Statement — Utility cost of fuel, natural gas, and purchased power	—			0.1
Natural gas contracts	Income Statement — Operating and maintenance expense	0.2			—
FTRs	Balance Sheet — Regulatory assets (current)	0.2			0.4
FTRs	Balance Sheet — Regulatory liabilities (current)	(0.4		)	(0.3		)
Petroleum product contracts	Balance Sheet — Regulatory assets (current)	—			0.1
Petroleum product contracts	Balance Sheet — Regulatory liabilities (current)	—			0.1
Petroleum product contracts	Income Statement — Operating and maintenance expense	—			0.1
Coal contracts	Balance Sheet — Regulatory assets (current)	1.9			(3.1		)
Coal contracts	Balance Sheet — Regulatory assets (long-term)	2.3			(3.5		)
Coal contracts	Balance Sheet — Regulatory liabilities (current)	(0.2		)	—
Coal contracts	Balance Sheet — Regulatory liabilities (long-term)	(2.2		)	—

9

Nonregulated Segments

NonHedge Derivatives

Integrys Energy Services enters into derivative contracts such as futures, forwards, options, and swaps that are used to manage commodity price risk primarily associated with retail electric and natural gas customer contracts.

Integrys Energy Services had the following notional volumes of outstanding nonhedge derivative contracts:

	March 31, 2013		December 31, 2012
(Millions)	Purchases	Sales	Purchases	Sales
Commodity contracts
Natural gas (therms)	641.5	556.2	782.0	679.0
Electric (kilowatt-hours)	56,100.1	34,502.0	54,127.6	31,809.6
Foreign exchange contracts (Canadian dollars)	0.4	0.4	0.4	0.4

Gains (losses) related to nonhedge derivatives are recognized currently in earnings, as shown in the table below:

		Three Months Ended March 31
(Millions)	Income Statement Presentation	2013			2012
Natural gas contracts	Nonregulated revenue	$	3.4		$	4.0
Natural gas contracts	Nonregulated cost of sales	(1.6		)	—
Natural gas contracts	Nonregulated revenue (reclassified from accumulated OCI) *	(0.1		)	(1.2		)
Electric contracts	Nonregulated revenue	64.0			(68.6		)
Electric contracts	Nonregulated revenue (reclassified from accumulated OCI) *	(1.0		)	(0.7		)
Total		$	64.7		$	(66.5	)

* Represents amounts reclassified from accumulated OCI related to cash flow hedges that were dedesignated in prior periods.

In the next 12 months, pre-tax losses of $0.1 million and $2.4 million related to discontinued cash flow hedges of natural gas contracts and electric contracts, respectively, are expected to be recognized in earnings as the forecasted transactions occur. These amounts are expected to be offset by the settlement of the related nonderivative customer contracts.

NOTE 4 — ACQUISITIONS

Acquisition of Fox Energy Center

In March 2013, WPS acquired all of the equity interests in Fox Energy Company LLC for $391.6 million, subject to post-closing working capital adjustments. Fox Energy Company LLC was dissolved into WPS immediately after the purchase.

The purchase included the Fox Energy Center, a 593-megawatt combined-cycle electric generating facility located in Wisconsin, along with associated contracts. Fox Energy Center is a dual-fuel facility, equipped to use fuel oil, but expected to run primarily on natural gas. This plant gives WPS a more balanced mix of owned electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources. In giving its approval for the purchase, the PSCW stated that the purchase price was reasonable and will benefit ratepayers.

The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:

(Millions)
Assets acquired
Inventories	$	3.0
Other current assets	0.6
Property, plant, and equipment	374.4
Other long-term assets *	15.6
Total assets acquired	$	393.6
Liabilities assumed
Accounts payable	$	2.0
Total liabilities assumed	$	2.0

* Relates to intangible assets recorded for contractual services agreements. See Note 8, "Goodwill and Other Intangible Assets," for more information.

10

Prior to the purchase, WPS supplied natural gas for the facility and purchased 500 megawatts of capacity and the associated energy output under a tolling arrangement. WPS paid $50.0 million for the early termination of the tolling arrangement. This amount was recorded as a regulatory asset, as WPS is authorized recovery by the PSCW.

The purchase was financed with a combination of short-term debt and cash flow from operations. The short-term debt will be replaced later in 2013 with long-term financing.

WPS received regulatory approval to defer incremental costs associated with the purchase of the facility. Operating costs for the Fox Energy Center subsequent to the date of acquisition are included in our income statement. Due to regulatory deferral, these costs had no impact on net income. Pro forma adjustments to our revenues and earnings prior to the date of acquisition would not be meaningful or material. Prior to the acquisition, the Fox Energy Center was a nonregulated plant and sold all of its output to third parties, with most of the output purchased by WPS. The plant is now part of WPS's regulated fleet, used to serve its customers.

Acquisition of Compass Energy Services

In May 2013, Integrys Energy Services acquired all of the equity interests of Compass Energy Services, Inc. and its wholly-owned subsidiary (“Compass”), a nonregulated retail natural gas business supplying commercial and industrial customers primarily in the Mid Atlantic and Ohio regions. This transaction will expand Integrys Energy Services' retail natural gas presence in these markets and provide a solid foundation for future growth in these regions.

This acquisition is not material to us. Integrys Energy Services made an initial cash payment of $12.0 million upon closing, and under the terms of the purchase agreement, the former owners of Compass will be eligible to receive additional cash consideration of up to $8.0 million (but no less than $3.0 million), based upon the financial performance of Compass over the next five years. Due to the timing of this acquisition, certain disclosures, including the allocation of the purchase price, have been omitted because the initial accounting for the business combination was incomplete as of the filing date.

NOTE 5 — DISCONTINUED OPERATIONS

Discontinued Operations at Holding Company and Other Segment

During the three months ended March 31, 2013, and 2012, we recorded $6.0 million and $1.9 million of after-tax gains, respectively, in discontinued operations at the holding company and other segment. 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.

Discontinued Operations at Integrys Energy Services Segment

Potential Sale of Combined Locks Energy Center

Integrys Energy Services is currently pursuing the sale of the Combined Locks Energy Center (Combined Locks), a natural gas-fired co-generation facility located in Wisconsin, as part of its long-term energy asset strategy. The sale of Combined Locks is expected to be completed by the end of 2013.

The carrying values of the major classes of assets related to Combined Locks classified as held for sale on the balance sheets were as follows:

(Millions)	March 31, 2013		December 31, 2012
Inventories	$	0.5	$	0.5
Property, plant, and equipment, net of accumulated depreciation of $0.5 million	2.0		2.0
Total assets	$	2.5	$	2.5

11

A summary of the components of discontinued operations related to Combined Locks recorded on the income statements was as follows at March 31:

(Millions)	2013			2012
Nonregulated revenues	$	—		$	0.4
Nonregulated cost of sales	(0.1		)	(0.3		)
Operating and maintenance expense	(0.1		)	(0.2		)
Depreciation and amortization expense	—			(0.1		)
Taxes other than income taxes	—			(0.1		)
Loss before taxes	(0.2		)	(0.3		)
Benefit for income taxes	0.1			0.1
Discontinued operations, net of tax	$	(0.1	)	$	(0.2	)

Sale of WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC

In March 2013, WPS Empire State, Inc, a subsidiary of Integrys Energy Services, sold all of the membership interests of WPS Beaver Falls Generation, LLC (Beaver Falls) and WPS Syracuse Generation, LLC (Syracuse), both of which own natural gas-fired generation plants located in the state of New York. The cash proceeds from the sale were $1.6 million, subject to certain post-closing adjustments primarily related to working capital. The sale agreement also includes a potential annual payment to Integrys Energy Services for a four-year period following the sale based on a certain level of earnings achieved by the buyer (an earn-out).

The carrying values of the major classes of assets and liabilities related to Beaver Falls and Syracuse classified as held for sale on the balance sheets were as follows:

(Millions)	As of the Closing Date on March 14, 2013		As of December 31, 2012
Inventories	$	1.8	$	1.8
Other current assets	0.2		—
Property, plant, and equipment	5.7		5.7
Other long-term assets	0.1		0.1
Total assets	$	7.8	$	7.6
Total liabilities – other current liabilities	$	0.4	$	0.2

In conjunction with the sale, the buyer will assume certain derivative contracts with Integrys Energy Services. The derivative contracts establish physical capacity hedges for the retail electric business and physical hedges associated with the sale of capacity to external counterparties. Integrys Energy Services is in the process of novating the external capacity sales contracts to the buyer, upon which time the corresponding purchase transactions with the buyer will terminate. The carrying value of the derivative contract liabilities assumed by the buyer were $6.8 million at March 31, 2013.

A summary of the components of discontinued operations related to Beaver Falls and Syracuse recorded on the income statements were as follows at March 31:

(Millions)	2013			2012
Nonregulated revenues	$	1.2		$	(0.7	)
Nonregulated cost of sales	(0.9		)	(0.4		)
Operating and maintenance expense *	0.4			(0.5		)
Depreciation and amortization expense	—			(0.2		)
Taxes other than income taxes	(0.3		)	(0.8		)
Income (loss) before taxes	0.4			(2.6		)
(Provision) benefit for income taxes	(0.2		)	1.0
Discontinued operations, net of tax	$	0.2		$	(1.6	)

* Includes a $1.0 million gain on sale at closing.

The sale of Beaver Falls and Syracuse will generate immaterial cash flows from providing certain administrative transition services to the buyer for up to a six-month period following the sale and from the potential four-year annual earn-out payment. Integrys Energy Services will also continue to purchase capacity from these facilities to satisfy certain capacity obligations, until novated to the buyer, and settle certain forward financial natural gas swaps under contracts that existed at the time of sale. Both of these transactions will generate cash flows that will expire upon novation or

12

within two years of the sale and are not considered significant to the overall operations of Beaver Falls and Syracuse. Integrys Energy Services does not have the ability to significantly influence the operating or financial policies of Beaver Falls and Syracuse and also does not have significant continuing involvement in the operations of Beaver Falls and Syracuse. Therefore, the continuing cash flows discussed above are not considered direct cash flows of Beaver Falls and Syracuse.

Sale of WPS Westwood Generation, LLC

In November 2012, Sunbury Holdings, LLC, a subsidiary of Integrys Energy Services, sold all of the membership interests of WPS Westwood Generation, LLC (Westwood), a waste coal generation plant located in Pennsylvania. The cash proceeds related to the sale were $2.6 million. Integrys Energy Services also received a $4.0 million note receivable from the buyer with a seven and one-half year term.

A summary of the components of discontinued operations related to Westwood recorded on the income statements were as follows at March 31:

(Millions)	2012
Nonregulated revenues	$	4.1
Nonregulated cost of sales	(1.3		)
Operating and maintenance expense	(1.0		)
Depreciation and amortization expense	(0.3		)
Taxes other than income taxes	(0.1		)
Interest expense	(0.1		)
Income before taxes	1.3
Provision for income taxes	(0.5		)
Discontinued operations, net of tax	$	0.8

Integrys Energy Services will receive interest income for seven and one-half years from the sale date related to the note receivable from the buyer. The sale will also generate immaterial cash flows from providing certain administrative transition services to the buyer for up to a six-month period following the sale. However, Integrys Energy Services does not have the ability to significantly influence the operating or financial policies of Westwood and also does not have significant continuing involvement in the operations of Westwood. Therefore, the continuing cash flows discussed above are not considered direct cash flows of Westwood.

NOTE 6 — INVESTMENT IN ATC

Our electric transmission investment segment consists of WPS Investments LLC’s ownership interest in ATC, which was approximately 34% at March 31, 2013. ATC is a for-profit, transmission-only company regulated by FERC.

The following table shows changes to our investment in ATC.

	Three Months Ended March 31
(Millions)	2013		2012
Balance at the beginning of period	$	476.6	$	439.4
Add: Earnings from equity method investment	21.7		20.8
Add: Capital contributions	1.7		3.4
Less: Dividends received	17.3		16.7
Balance at the end of period	$	482.7	$	446.9

Financial data for all of ATC is included in the following tables:

	Three Months Ended March 31
(Millions)	2013		2012
Income statement data
Revenues	$	151.8	$	147.7
Operating expenses	69.8		69.6
Other expense	21.5		20.0
Net income	$	60.5	$	58.1

13

(Millions)	March 31, 2013		December 31, 2012
Balance sheet data
Current assets	$	69.3	$	63.1
Noncurrent assets	3,325.3		3,274.7
Total assets	$	3,394.6	$	3,337.8
Current liabilities	$	261.5	$	251.5
Long-term debt	1,550.0		1,550.0
Other noncurrent liabilities	124.8		95.8
Shareholders’ equity	1,458.3		1,440.5
Total liabilities and shareholders’ equity	$	3,394.6	$	3,337.8

NOTE 7 — INVENTORIES

PGL and NSG price natural gas storage injections at the calendar year average of the cost of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At March 31, 2013, we had a temporary LIFO liquidation credit of $83.2 million recorded within other current liabilities on our balance sheet. Due to seasonality requirements, PGL and NSG expect interim reductions in LIFO layers to be replenished by year end.

NOTE 8 — GOODWILL AND OTHER INTANGIBLE ASSETS

We had no material changes to the carrying amount of goodwill during the three months ended March 31, 2013, and 2012.

In connection with the acquisition of Fox Energy Company LLC, WPS recorded $15.6 million of intangible assets in the first quarter of 2013. The intangible assets relate to contractual service agreements, which provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The approximate amortization period of these intangible assets is 7 years.

The identifiable intangible assets other than goodwill listed below are part of other long-term assets on the balance sheets. An insignificant amount was recorded as assets held for sale on the balance sheets.

	March 31, 2013							December 31, 2012
(Millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets
Customer-related (1)	$	22.4	$	(15.0	)	$	7.4	$	22.4	$	(14.7	)	$	7.7
Contractual service agreements (2)	15.6		—			15.6		—		—			—
Patents/intellectual property (3)	7.2		(0.3		)	6.9		7.2		(0.3		)	6.9
Compressed natural gas fueling contract assets (4)	5.6		(1.7		)	3.9		5.6		(1.3		)	4.3
Renewable energy credits (5)	5.1		—			5.1		3.1		—			3.1
Nonregulated easements (6)	3.8		(1.0		)	2.8		3.8		(0.9		)	2.9
Customer-owned equipment modifications (7)	4.0		(0.6		)	3.4		4.0		(0.5		)	3.5
Other	0.5		(0.3		)	0.2		0.5		(0.2		)	0.3
Total	$	64.2	$	(18.9	)	$	45.3	$	46.6	$	(17.9	)	$	28.7
Unamortized intangible assets
MGU trade name	$	5.2	$	—		$	5.2	$	5.2	$	—		$	5.2
Trillium trade name	3.5		—			3.5		3.5		—			3.5
Pinnacle trade name	1.5		—			1.5		1.5		—			1.5
Total intangible assets	$	74.4	$	(18.9	)	$	55.5	$	56.8	$	(17.9	)	$	38.9

⁽¹⁾  Represents customer relationship assets associated with PELLC’s former nonregulated retail natural gas and electric operations and Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) compressed natural gas fueling operations. The remaining weighted-average amortization period for customer-related intangible assets at March 31, 2013, was approximately 9 years.

⁽²⁾  Represents contractual service agreements related to maintenance on the combustion turbine generators at the Fox Energy Center. The remaining amortization period for these intangible assets at March 31, 2013, was approximately 7 years.

⁽³⁾  Represents the fair value of patents/intellectual property at Pinnacle related to a system for more efficiently compressing natural gas to allow for faster fueling. The remaining amortization period at March 31, 2013, was approximately 9 years.

14

⁽⁴⁾  Represents the fair value of Trillium and Pinnacle contracts acquired in September 2011. The remaining amortization period at March 31, 2013, was approximately 8 years.

⁽⁵⁾  Used at Integrys Energy Services to comply with state Renewable Portfolio Standards and to support customer commitments.

⁽⁶⁾  Relates to easements supporting a pipeline at Integrys Energy Services. The easements are amortized on a straight-line basis, with a remaining amortization period at March 31, 2013, of approximately 11 years.

⁽⁷⁾  Relates to modifications made by Integrys Energy Services and Trillium to customer-owned equipment. These intangible assets are amortized on a straight-line basis, with a remaining weighted-average amortization period at March 31, 2013, of approximately 11 years.

Amortization expense recorded as a component of nonregulated cost of sales in the statements of income for the three months ended March 31, 2013, and 2012, was $0.4 million and $1.6 million, respectively.

Amortization expense recorded as a component of depreciation and amortization expense in the statements of income for the three months ended March 31, 2013, and 2012, was $0.5 million and $0.7 million, respectively.

An insignificant amount of amortization expense was recorded in discontinued operations for the three months ended March 31, 2013, and 2012.

Amortization expense for the next five fiscal years is estimated to be:

	For the Year Ending December 31
(Millions)	2013		2014		2015		2016		2017
Amortization to be recorded in nonregulated cost of sales	$	6.7	$	1.2	$	1.1	$	0.9	$	0.9
Amortization to be recorded in depreciation and amortization expense	3.8		4.1		4.1		3.9		3.8

NOTE 9 — SHORT-TERM DEBT AND LINES OF CREDIT

Our outstanding short-term borrowings were as follows:

(Millions, except percentages)	March 31, 2013		December 31, 2012
Commercial paper	$	556.4	$	482.4
Average discount rate on commercial paper	0.33%		0.40%
Loan under term credit facility *	$	200.0	—
Average interest rate on loan under term credit facility	0.80%		—

* Relates to the purchase of Fox Energy Company LLC. See Note 4, "Acquisitions," for more information regarding this purchase.

The commercial paper outstanding at March 31, 2013, had maturity dates ranging from April 1, 2013, through May 24, 2013. The terms of the loan outstanding under the term credit facility require repayment upon the earlier of issuance of replacement long-term debt or December 31, 2013.

The table below presents our average amount of short-term borrowings based on daily outstanding balances during the three months ended March 31:

(Millions)	2013		2012
Average amount of commercial paper	$	400.7	$	357.5
Average amount of loan under term credit facility	8.9		—

15

We manage our liquidity by maintaining adequate external financing commitments. The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities, and our short-term debt:

(Millions)	Maturity	March 31, 2013		December 31, 2012
Revolving credit facility (Integrys Energy Group)	05/17/2014	$	275.0	$	275.0
Revolving credit facility (Integrys Energy Group)	05/17/2016	200.0		200.0
Revolving credit facility (Integrys Energy Group)	06/13/2017	635.0		635.0
Revolving credit facility (WPS)	05/17/2014	135.0		135.0
Revolving credit facility (WPS)	06/13/2017	115.0		115.0
Revolving credit facility (PGL)	06/13/2017	250.0		250.0
Term credit facility (WPS) *	12/31/2013	200.0		—
Total short-term credit capacity		$	1,810.0	$	1,610.0
Less:
Letters of credit issued inside credit facilities		$	29.1	$	25.5
Loan outstanding under term credit facility *		200.0		—
Commercial paper outstanding		556.4		482.4
Accrued interest or original discount on outstanding commercial paper		0.1		—
Available capacity under existing agreements		$	1,024.4	$	1,102.1

* Relates to the purchase of Fox Energy Company LLC. See Note 4, "Acquisitions," for more information regarding this purchase.

NOTE 10 — LONG-TERM DEBT

(Millions)	March 31, 2013			December 31, 2012
WPS (1)	$	850.1		$	872.1
PGL (2)	625.0			625.0
NSG (3)	74.5			74.5
Integrys Energy Group	674.8			674.8
Total	2,224.4			2,246.4
Unamortized discount on debt	(1.2		)	(1.2		)
Total debt	2,223.2			2,245.2
Less current portion	(291.5		)	(313.5		)
Total long-term debt	$	1,931.7		$	1,931.7

⁽¹⁾  In February 2013, WPS’s $22.0 million of 3.95% Senior Notes matured, and the outstanding principal balance was repaid.

In December 2013, WPS’s 4.80% Senior Notes will mature. As a result, the $125.0 million balance of these notes was included in the current portion of long-term debt on our balance sheets.

⁽²⁾  In April 2013, PGL bought back its $50.0 million of 5.00% Series KK First and Refunding Mortgage Bonds that were due in February 2033.

In the same month, PGL issued $50.0 million of 4.00% Series ZZ First and Refunding Mortgage Bonds. These bonds are due in February 2033.

On May 1, 2013, PGL’s 4.625% Series NN-2 First and Refunding Mortgage Bonds matured, and the outstanding principal balance was repaid. As a result, the $75.0 million balance of these bonds was included in the current portion of long-term debt on our balance sheets.

In November 2013, PGL’s 7.00% Series SS First and Refunding Mortgage Bonds will mature. As a result, the $45.0 million balance of these bonds was included in the current portion of long-term debt on our balance sheets.

⁽³⁾  On May 1, 2013, NSG issued $54.0 million of 3.96% Series Q First Mortgage Bonds. These bonds are due in May 2043.

On May 1, 2013, NSG’s 4.625% Series N-2 First Mortgage Bonds matured, and the outstanding principal balance was repaid. As a result, the $40.0 million balance of these bonds was included in the current portion of long-term debt on our balance sheets.

In November 2013, NSG’s 7.00% Series O First Mortgage Bonds will mature. As a result, the $6.5 million balance of these bonds was included in the current portion of long-term debt on our balance sheets.

On May 1, 2013, PGL secured commitments for $220.0 million of 30-year 3.96% Series AAA First and Refunding Mortgage Bonds with a delayed draw feature. These bonds will be issued in August 2013.

16

NOTE 11 — INCOME TAXES

We calculate our interim period provision for income taxes based on our projected annual effective tax rate as adjusted for certain discrete items.

The table below shows our effective tax rates:

	Three Months Ended March 31
	2013		2012
Effective Tax Rate	37.6	%	32.4	%

Our effective tax rate normally differs from the federal statutory tax rate of 35% due to additional provision for multistate income tax obligations. Other significant items that had an impact on our effective tax rates are noted below.

Our effective tax rate for the three months ended March 31, 2012, was lowered by the federal income tax benefit of wind production tax credits (PTCs). The effective income tax rate in 2013 was not impacted by wind PTCs. In the fourth quarter of 2012, we elected to claim and subsequently received a Section 1603 Grant for WPS's Crane Creek Wind Project in lieu of wind PTCs.

Our effective tax rate for the three months ended March 31, 2012, was also lowered by the effective settlement of certain state income tax examinations and a remeasurement of uncertain tax positions included in our liability for unrecognized tax benefits.

During the three months ended March 31, 2013, we decreased our liability for unrecognized tax benefits by $6.8 million. This decrease primarily related to a remeasurement of uncertain tax positions driven by an effective settlement of 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.

NOTE 12 — COMMITMENTS AND CONTINGENCIES

(a) Unconditional Purchase Obligations and Purchase Order Commitments

We and our subsidiaries routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. The regulated natural gas utilities have obligations to distribute and sell natural gas to their customers, and the regulated electric utilities have obligations to distribute and sell electricity to their customers. The utilities expect to recover costs related to these obligations in future customer rates. Additionally, the majority of the energy supply contracts entered into by Integrys Energy Services are to meet its obligations to deliver energy to customers. The following table shows our minimum future commitments related to these purchase obligations as of March 31, 2013, including those of our subsidiaries.

				Payments Due By Period
(Millions)	Date Contracts Extend Through	Total Amounts Committed		2013		2014		2015		2016		2017		Later Years
Natural gas utility supply and transportation	2028	$	823.2	$	124.9	$	156.3	$	137.9	$	125.7	$	86.9	$	191.5
Electric utility
Purchased power	2029	852.6		121.3		37.7		33.0		29.4		28.4		602.8
Coal supply and transportation	2017	122.7		44.4		41.2		30.4		6.2		0.5		—
Nonregulated electricity and natural gas supply	2020	830.6		479.8		305.9		34.3		4.6		1.3		4.7
Total		$	2,629.1	$	770.4	$	541.1	$	235.6	$	165.9	$	117.1	$	799.0

We and our subsidiaries also had commitments of $713.5 million in the form of purchase orders issued to various vendors at March 31, 2013, that relate to normal business operations, including construction projects.

(b) Environmental Matters

Air Permitting Violation Claims

Weston and Pulliam Clean Air Act (CAA) Issues:

In November 2009, the EPA issued a Notice of Violation (NOV) to WPS alleging violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. WPS reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree, which was filed in the U.S. District Court (Court) in January 2013. This Consent Decree was approved by the Court in March 2013, after a public comment period. The final Consent Decree includes:

• the installation of emission control technology, including ReACT™ or an approved alternative, on Weston 3,

• changed operating conditions (including refueling, repowering, and/or retirement of units),

• limitations on plant emissions,

17

• beneficial environmental projects totaling $6.0 million (various options, including capital projects, are available), and

• a civil penalty of $1.2 million.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. As of March 31, 2013, no decision had been made on how to address this requirement. Therefore, retirement of the Weston and Pulliam units mentioned in the Consent Decree was not considered probable.

We believe that significant costs prudently incurred as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty, will be recoverable from customers.

In May 2010, WPS received from the Sierra Club a Notice of Intent (NOI) to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of March 31, 2013. It is unknown whether the Sierra Club will take further action in the future.

Columbia and Edgewater CAA Issues:

In December 2009, the EPA issued an NOV to Wisconsin Power and Light (WP&L), the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric and WPS. The NOV alleges violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, WP&L, and Madison Gas and Electric (Joint Owners) reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree, which was filed in the Court on April 22, 2013. The Consent Decree includes:

• the installation of emission control technology, including the installation of scrubbers at the Columbia plant,

• changed operating conditions (including refueling, repowering, and/or retirement of units),

• limitations on plant emissions,

• beneficial environmental projects, with WPS's portion totaling $1.3 million (various options, including capital projects, are available), and

• WPS's portion of a civil penalty and legal fees totaling $0.4 million.

The public comment period will end on May 28, 2013. The final terms of the Consent Decree may be different than currently anticipated.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain of the Columbia and Edgewater units. As of March 31, 2013, no decision had been made on how to address this requirement. Therefore, retirement of the Colombia and Edgewater units mentioned in the Consent Decree was not considered probable.

We believe that significant costs prudently incurred as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty, will be recoverable from customers.

In September 2010, the Sierra Club filed a lawsuit against WP&L, which included allegations that modifications made at the Edgewater plant did not comply with the CAA. A similar case had also been filed by the Sierra Club related to the Columbia plant, which was dismissed without prejudice due to the impending settlement and Consent Decree. As part of the Consent Decree settlement, the Sierra Club filed a new suit related to the Columbia plant, which gave notice of the filing of the Consent Decree. It is anticipated that the Sierra Club will dismiss both suits against WP&L once the Consent Decree is approved by the Court.

Weston Title V Air Permit:

In November 2010, the WDNR provided a draft revised permit for the Weston 4 plant. WPS objected to proposed changes in mercury limits and requirements on the boilers as beyond the authority of the WDNR and met with the WDNR to resolve these issues. In September 2011, the WDNR issued an updated draft revised permit and a request for public comments. Due to the significance of the changes to the draft revised permit, the WDNR re-issued the draft revised permit for additional comments in February 2013. In July 2012, Clean Wisconsin filed suit against the WDNR alleging failure to issue or delay in issuing the Weston Title V permit. WPS and the WDNR both filed motions to dismiss Clean Wisconsin's lawsuit, which the Court granted in February 2013. Clean Wisconsin appealed this decision, but briefs have not yet been filed in the appeal. We do not expect this matter to have a material impact on our financial statements.

Pulliam Title V Air Permit:

The WDNR issued a renewal of the permit for the Pulliam plant in April 2009. In June 2010, the EPA issued an order directing the WDNR to respond to comments raised by the Sierra Club in its June 2009 petition requesting the EPA to object to the permit.

In April 2011, WPS received notification that the Sierra Club filed a civil lawsuit against the EPA based on what the Sierra Club alleged to be an unreasonable delay in responding to the June 2010 order. WPS is not a party to this litigation, but intervened to protect its interests. In February 2012, the WDNR sent a proposed permit and response to the EPA for a 45-day review, which allowed the parties to enter into a settlement agreement that has been approved by the Court.

18

In May 2012, the Sierra Club filed another petition requesting that the EPA again object to the proposed permit and response, which the EPA denied in January 2013. The Sierra Club did not appeal the EPA decision. The Sierra Club also recently filed a request for a contested case proceeding regarding the permit, which was granted in part by the WDNR. A schedule has not yet been set for the contested case proceeding.

We are reviewing all of these matters, but we do not expect them to have a material impact on our financial statements.

Columbia Title V Air Permit:

In February 2011, the Sierra Club filed a lawsuit against the EPA seeking to have the EPA take over the Title V permit process for the Columbia plant. The Sierra Club alleges the EPA must now act on the reconsideration of the Title V permit since the WDNR has exceeded its time frame in which to respond to an EPA order issued in 2009. In May 2011, the WDNR issued a revised draft Title V permit in response to the EPA's order.

In June 2012, WP&L received notice from the EPA of the EPA's proposal for WP&L to apply for a federally-issued Title V permit since the WDNR has not addressed the EPA's objections to the Title V permit issued for the Columbia plant. A hearing has been set for June 3, 2013. If the EPA decides to require the submittal of an operation permit application, it would be due within six months of the EPA's notice to WP&L. WP&L believes the previously issued Title V permit for the Columbia plant is still valid.

We do not expect this matter to have a material impact on our financial statements.

WDNR Issued NOVs:

Since 2008, WPS has received four NOVs from the WDNR alleging various violations of the different air permits for the entire Weston plant and Weston 1, Weston 2, and Weston 4 individually. WPS also received an NOV for a clerical error involving pages missing from a quarterly report for Weston. Corrective actions have been taken for the events in the five NOVs. In December 2011, the WDNR referred several of the claims in the NOVs to the state Justice Department for enforcement. WPS began discussing the pending NOVs and their resolution with the Justice Department in late 2012. We do not expect this matter to have a material impact on our financial statements.

Weston 4 Construction Permit

From 2004 to 2009, the Sierra Club filed various petitions objecting to the construction permit issued for the Weston 4 plant. In June 2010, the Wisconsin Court of Appeals affirmed the Weston 4 construction permit, but directed the WDNR to reopen the permit to set specific visible emissions limits. In July 2010, WPS, the WDNR, and the Sierra Club filed Petitions for Review with the Wisconsin Supreme Court. In March 2011, the Wisconsin Supreme Court denied all Petitions for Review. Other than the specific visible emissions limits issue, all other challenges to the construction permit are now resolved. WPS is working with the WDNR to resolve this issue as part of the current construction permit renewal process. We do not expect this matter to have a material impact on our financial statements.

Mercury and Interstate Air Quality Rules

Mercury:

The State of Wisconsin's mercury rule requires a 40% reduction from historical baseline mercury emissions, beginning January 1, 2010, through the end of 2014. Beginning in 2015, electric generating units above 150 megawatts will be required to reduce mercury emissions by 90% from the historical baseline. Reductions can be phased in and the 90% target delayed until 2021 if additional sulfur dioxide and nitrogen oxide reductions are implemented. By 2015, electric generating units above 25 megawatts, but less than 150 megawatts, must reduce their mercury emissions to a level defined by the Best Available Control Technology rule. As of March 31, 2013, WPS estimates capital costs of approximately $8 million for its wholly owned plants to achieve the required reductions. The capital costs are expected to be recovered in future rates.

In December 2011, the EPA issued the final Utility Mercury and Air Toxics Standards (MATS), which will regulate emissions of mercury and other hazardous air pollutants beginning in 2015. The State of Wisconsin is assessing how its current mercury rule will be impacted by the MATS rule. We are currently evaluating options for achieving the emission limits specified in this rule, but we do not anticipate the cost of compliance to be significant. We expect to recover future compliance costs in future rates.

Sulfur Dioxide and Nitrogen Oxide:

In July 2011, the EPA issued a final rule known as the Cross State Air Pollution Rule (CSAPR), which numerous parties, including WPS, challenged in the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). The new rule was to become effective January 1, 2012. However, in December 2011, the CSAPR requirements were stayed by the D.C. Circuit and a previous rule, the Clean Air Interstate Rule (CAIR), was implemented during the stay period. In August 2012, the D.C. Circuit issued their ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. In October 2012, the EPA and several other parties filed petitions for a rehearing of the D.C. Circuit's decision, which the D.C. Circuit denied in January 2013.

Under CAIR, units affected by the Best Available Retrofit Technology (BART) rule were considered in compliance with BART for sulfur dioxide and nitrogen oxide emissions if they were in compliance with CAIR. This determination was updated when CSAPR was issued (CSAPR satisfied BART), and the EPA has not revised it to reflect the reinstatement of CAIR. Although particulate emissions also contribute to visibility impairment, the WDNR's modeling has shown the impairment to be so insignificant that additional capital expenditures on controls are not warranted.

19

Due to the uncertainty surrounding this rulemaking, we are currently unable to predict whether WPS will have to purchase additional emission allowances, idle or abandon certain units, or change how certain units are operated. WPS expects to recover any future compliance costs in future rates. The potential impact on Integrys Energy Services is not expected to be material.

Manufactured Gas Plant Remediation

Our natural gas utilities, their predecessors, and certain former affiliates operated facilities in the past at multiple sites for the purpose of manufacturing and storing manufactured gas. In connection with these activities, waste materials were produced that may have resulted in soil and groundwater contamination at these sites. Under certain laws and regulations relating to the protection of the environment, our natural gas utilities are required to undertake remedial action with respect to some of these materials. They are coordinating the investigation and cleanup of the sites subject to EPA jurisdiction under what is called a "multi-site" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies.

Our natural gas utilities are responsible for the environmental remediation of 53 sites, of which 20 have been transferred to the EPA Superfund Alternative Sites Program. Under the EPA's program, the remedy decisions at these sites will be made using risk-based criteria typically used at Superfund sites. As of March 31, 2013, we estimated and accrued for $639.6 million of future undiscounted investigation and cleanup costs for all sites. We may adjust these estimates in the future due to remedial technology, regulatory requirements, remedy determinations, and any claims of natural resource damages. As of March 31, 2013, cash expenditures for environmental remediation not yet recovered in rates were $30.0 million. We recorded a regulatory asset of $669.6 million at March 31, 2013, which is net of insurance recoveries received of $63.1 million, related to the expected recovery through rates of both cash expenditures and estimated future expenditures.

Management believes that any costs incurred for environmental activities relating to former manufactured gas plant operations that are not recoverable through contributions from other entities or from insurance carriers have been prudently incurred and are, therefore, recoverable through rates for MGU, NSG, PGL, and WPS. Accordingly, we do not expect these costs to have a material impact on our financial statements. However, any changes in the approved rate mechanisms for recovery of these costs, or any adverse conclusions by the various regulatory commissions with respect to the prudence of costs actually incurred, could materially affect recovery of such costs through rates.

NOTE 13 — GUARANTEES

The following table shows our outstanding guarantees:

	Total Amounts Committed at March 31, 2013		Expiration
(Millions)			Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees supporting commodity transactions of subsidiaries (1)	$	597.1	$	368.8	$	31.3	$	197.0
Standby letters of credit (2)	34.2		34.1		0.1		—
Surety bonds (3)	14.4		14.4		—		—
Other guarantees (4)	22.3		—		—		22.3
Total guarantees	$	668.0	$	417.3	$	31.4	$	219.3

⁽¹⁾  Consists of parental guarantees of $436.3 million to support the business operations of Integrys Energy Services; $108.5 million and $45.3 million, respectively, related to natural gas supply at MERC and MGU; and $5.0 million at IBS, and $2.0 million at UPPCO to support business operations. These guarantees are not reflected on our balance sheets.

⁽²⁾  At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. This amount consists of $32.5 million issued to support Integrys Energy Services’ operations and $1.7 million issued to support MERC, MGU, NSG, PGL, Pinnacle CNG Systems, UPPCO, and WPS. These amounts are not reflected on our balance sheets.

⁽³⁾  Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These guarantees are not reflected on our balance sheets.

⁽⁴⁾  Consists of (a) $10.0 million related to the sale agreement for Integrys Energy Services’ Texas retail marketing business, which included a number of customary representations, warranties, and indemnification provisions. An insignificant liability was recorded related to the possible imposition of additional miscellaneous gross receipts tax in the event of a change in law or interpretation of the tax law; (b) $5.0 million related to an environmental indemnification provided by Integrys Energy Services as part of the sale of the Stoneman generation facility, under which we expect that the likelihood of required performance is remote. This amount is not reflected on our balance sheets; and (c) $7.3 million related to other indemnifications primarily for workers compensation coverage. These amounts are not reflected on our balance sheets.

We have provided total parental guarantees of $487.0 million on behalf of Integrys Energy Services. Our exposure under these guarantees related to existing transactions at March 31, 2013, was approximately $229.7 million.

20

NOTE 14 — EMPLOYEE BENEFITS PLANS

The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans:

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended, March 31,						Three Months Ended, March 31,
(Millions)	2013			2012			2013			2012
Service cost	$	7.5		$	12.4		$	6.5		$	5.5
Interest cost	17.8			19.8			6.3			7.2
Expected return on plan assets	(26.6		)	(27.1		)	(7.7		)	(7.0		)
Amortization of transition obligation	—			—			—			0.1
Amortization of prior service cost (credit)	1.0			1.2			(0.6		)	(0.9		)
Amortization of net actuarial loss	13.5			8.3			2.0			1.6
Net periodic benefit cost	$	13.2		$	14.6		$	6.5		$	6.5

Transition obligations, prior service costs (credits), and net actuarial losses that have not yet been recognized as a component of net periodic benefit cost are included in accumulated OCI for our nonregulated entities and are recorded as net regulatory assets for our utilities.

We make contributions to our plans in accordance with legal and tax requirements. These contributions do not necessarily occur evenly throughout the year. During the three months ended March 31, 2013, we contributed $63.2 million to our pension plans and contributions to our other postretirement benefit plans were not significant. We expect to contribute an additional $4.7 million to our pension plans and $32.8 million to our other postretirement benefit plans during the remainder of 2013, dependent upon various factors affecting us, including our liquidity position and tax law changes.

NOTE 15 — STOCK-BASED COMPENSATION

The following table reflects the stock-based compensation expense and the related deferred tax benefit recognized in income for the three months ended March 31:

(Millions)	2013		2012
Stock options	$	0.4	$	0.4
Performance stock rights	2.2		1.2
Restricted share units	2.8		2.1
Nonemployee director deferred stock units	0.3		1.0
Total stock-based compensation expense	$	5.7	$	4.7
Deferred income tax benefit	$	2.3	$	1.9

No stock-based compensation cost was capitalized during the three months ended March 31, 2013 and 2012.

Stock Options

The fair value of stock option awards granted is estimated using a binomial lattice model. The expected term of option awards is calculated based on historical exercise behavior and represents the period of time that options are expected to be outstanding. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. Our expected stock price volatility is estimated using its 10-year historical volatility. The following table shows the weighted-average fair value per stock option granted during the three months ended March 31, 2013, along with the assumptions incorporated into the valuation model:

	February 2013 Grant
Weighted-average fair value per option	$6.03
Expected term	5 years
Risk-free interest rate	0.18% – 2.11%
Expected dividend yield	5.33%
Expected volatility	24%

21

A summary of stock option activity for the three months ended March 31, 2013, and information related to outstanding and exercisable stock options at March 31, 2013, is presented below:

	Stock Options		Weighted-Average Exercise Price Per Share		Weighted-Average Remaining  Contractual Life (in Years)	Aggregate Intrinsic Value (Millions)
Outstanding at December 31, 2012	2,046,355		$	49.25
Granted	319,234		56.00
Exercised	(145,955	)	44.03
Outstanding at March 31, 2013	2,219,634		$	50.56	6.01	$	16.9
Exercisable at March 31, 2013	1,463,836		$	49.78	4.56	$	12.4

The aggregate intrinsic value for outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they all exercised their options at March 31, 2013. This is calculated as the difference between our closing stock price on March 31, 2013, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the three months ended March 31, 2013, and 2012, was $1.9 million and $2.0 million, respectively. The actual tax benefit realized for the tax deductions from these option exercises was not significant for the three months ended March 31, 2013, and 2012.

As of March 31, 2013, $2.6 million of compensation cost related to unvested and outstanding stock options was expected to be recognized over a weighted-average period of 2.0 years.

Performance Stock Rights

The fair values of performance stock rights are estimated using a Monte Carlo valuation model. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. The expected volatility is estimated using two to three years of historical data. The table below reflects the assumptions used in the valuation of the outstanding grants at March 31:

	2013
Risk-free interest rate	0.17% – 1.27%
Expected dividend yield	5.18% – 5.34%
Expected volatility	19% – 36%

A summary of the activity for the three months ended March 31, 2013, related to performance stock rights accounted for as equity awards is presented below:

	Performance Stock Rights		Weighted-Average Fair Value *
Outstanding at December 31, 2012	108,314		$	65.38
Granted	22,636		48.50
Distributed	(94,758	)	72.36
Adjustment for final payout	21,867		72.36
Outstanding at March 31, 2013	58,059		$	50.04

* Reflects the weighted-average fair value used to measure equity awards. Equity awards are measured using the grant date fair value or the fair value on the modification date.

The weighted-average grant date fair value of performance stock rights awarded during the three months ended March 31, 2013, and 2012, was $48.50 and $52.70, per performance stock right, respectively.

A summary of the activity for the three months ended March 31, 2013, related to performance stock rights accounted for as liability awards is presented below:

	Performance Stock Rights
Outstanding at December 31, 2012	189,093
Granted	90,496
Distributed	(61,753	)
Adjustment for final payout	14,255
Outstanding at March 31, 2013	232,091

The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of March 31, 2013, was $48.06 per performance stock right.

22

As of March 31, 2013, $5.9 million of compensation cost related to unvested and outstanding performance stock rights (equity and liability awards) was expected to be recognized over a weighted-average period of 1.5 years.

The total intrinsic value of performance stock rights distributed during the three months ended March 31, 2013, and 2012, was $8.8 million and $4.7 million, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance stock rights during the three months ended March 31, 2013, and 2012, was $3.6 million and $1.9 million, respectively.

Restricted Share Units

A summary of the activity related to all restricted share unit awards (equity and liability awards) for the three months ended March 31, 2013, is presented below:

	Restricted Share Unit Awards		Weighted-AverageGrant Date Fair Value
Outstanding at December 31, 2012	505,690		$	48.38
Granted	189,094		56.00
Dividend equivalents	5,818		52.20
Vested and released	(204,072	)	46.28
Forfeited	(1,507	)	48.47
Outstanding at March 31, 2013	495,023		$	52.20

As of March 31, 2013, $17.4 million of compensation cost related to these awards was expected to be recognized over a weighted-average period of 2.5 years.

The total intrinsic value of restricted share unit awards vested and released during the three months ended March 31, 2013, and 2012, was $11.4 million and $10.4 million, respectively. The actual tax benefit realized for the tax deductions from the vesting and release of restricted share units during the three months ended March 31, 2013, and 2012, was $4.6 million and $4.2 million, respectively.

The weighted-average grant date fair value of restricted share units awarded during the three months ended March 31, 2013, and 2012, was $56.00 and $53.24 per share, respectively.

Nonemployee Directors Deferred Stock Units

Each nonemployee director is granted deferred stock units (DSUs), typically in January of each year. The number of DSUs granted is calculated by dividing a set dollar amount by our closing common stock price on the date of the grant. Prior to January 1, 2013, under the terms of the agreement, these awards vested immediately, and therefore were expensed on the grant date. Beginning in 2013, these awards will generally vest over one year. Therefore, the expense for these awards will be recognized pro-rata over the year in which the grant occurs.

NOTE 16 — COMMON EQUITY

We had the following changes to issued common stock during the three months ended March 31, 2013:

Common stock at December 31, 2012	78,287,906
Shares issued
Stock Investment Plan	114,365
Stock-based compensation	317,677
Rabbi trust shares	90,000
Common stock at March 31, 2013	78,809,948

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 02/05/2013	Issuing new shares *
01/01/2012 – 02/04/2013	Purchased shares on the open market

^* These stock issuances increased equity $22.3 million in 2013.

23

The following table reconciles common shares issued and outstanding:

	March 31, 2013			December 31, 2012
	Shares	Average Cost *		Shares	Average Cost *
Common stock issued	78,809,948			78,287,906
Less:
Deferred compensation rabbi trust	456,852	$	48.23	385,439	$	46.03
Total common shares outstanding	78,353,096			77,902,467

* Based on our stock price on the day the shares entered the deferred compensation rabbi trust. Shares paid out of the trust are valued at the average cost of shares in the trust.

Earnings Per Share

Basic earnings per share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for shares we are obligated to issue under the deferred compensation and restricted share unit plans. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include in-the-money stock options, performance stock rights, restricted share units, and certain shares issuable under the deferred compensation plan. The calculations of diluted earnings per share for the three months ended March 31, 2013, and 2012, excluded 0.2 million and 0.8 million, respectively, out-of-the-money stock options that had an anti-dilutive effect. The following table reconciles our computation of basic and diluted earnings per share:

	Three Months Ended March 31
(Millions, except per share amounts)	2013			2012
Numerator:
Net income from continuing operations	$	182.2		$	98.8
Discontinued operations, net of tax	6.1			0.9
Preferred stock dividends of subsidiary	(0.8		)	(0.8		)
Net income attributed to common shareholders	$	187.5		$	98.9
Denominator:
Average shares of common stock — basic	78.7			78.6
Effect of dilutive securities
Stock-based compensation	0.4			0.4
Deferred compensation	0.2			0.2
Average shares of common stock — diluted	79.3			79.2
Earnings per common share
Basic	$	2.38		$	1.26
Diluted	2.37			1.25

Dividend Restrictions

Our ability as a holding company to pay dividends is largely dependent upon the availability of funds from our subsidiaries. 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.

The PSCW allows WPS to pay dividends on its common stock of no more than 103% of the previous year’s common stock dividend. WPS may return capital to us if its average financial common equity ratio is at least 51% on a calendar-year basis. WPS must obtain PSCW approval if a return of capital would cause its average financial common equity ratio to fall below this level. Our right to receive dividends on the common stock of WPS is also subject to the prior rights of WPS’s preferred shareholders and to provisions in WPS’s restated articles of incorporation, which limit the amount of common stock dividends that WPS may pay if its common stock and common stock surplus accounts constitute less than 25% of its total capitalization.

NSG’s long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock.

PGL and WPS have short-term debt obligations containing financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of their outstanding debt obligations.

24

We also have short-term and long-term debt obligations that contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of outstanding debt obligations. At March 31, 2013, these covenants did not restrict the payment of any dividends beyond the amount restricted under our subsidiary requirements described above.

As of March 31, 2013, total restricted net assets were $1,676.0 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $129.4 million at March 31, 2013.

We have the option to defer interest payments on our outstanding Junior Subordinated Notes, from time to time, for one or more periods of up to ten consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, purchase, acquire, or make a liquidation payment on, any of our capital stock.

Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.

Capital Transactions with Subsidiaries

During the three months ended March 31, 2013, capital transactions with subsidiaries were as follows (in millions):

Subsidiary	Dividends To Parent		Return Of  Capital To Parent		Equity Contributions From Parent
ITF (1)	$	—	$	—	$	11.7
MERC	—		21.0		—
WPS	27.1		—		200.0
WPS Investments, LLC (2)	17.3		—		1.7
Total	$	44.4	$	21.0	$	213.4

⁽¹⁾  ITF is a direct wholly owned subsidiary of PELLC. As a result, it makes distributions to PELLC, and receives equity contributions from PELLC. Subject to applicable law, PELLC does not have any dividend restrictions or limitations on distributions to us.

⁽²⁾  WPS Investments, LLC is a consolidated subsidiary that is jointly owned by us, WPS, and UPPCO. At March 31, 2013, we had an 85.86% ownership interest, while WPS and UPPCO had an 11.66% and 2.48% ownership interest, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2013, all equity contributions to WPS Investments, LLC were made solely by us.

NOTE 17 — ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table shows the changes, net of tax, to our accumulated other comprehensive loss from December 31, 2012 through March 31, 2013:

	Cash Flow Hedges			Defined Benefit Pension Plans			Accumulated Other Comprehensive Income (Loss)
Beginning balance at December 31, 2012	$	(5.2	)	$	(35.7	)	$	(40.9	)
Other comprehensive income before reclassifications	0.1			—			0.1
Amounts reclassified out of accumulated other comprehensive loss	0.9			0.6			1.5
Net current period other comprehensive income	1.0			0.6			1.6
Ending balance at March 31, 2013	$	(4.2	)	$	(35.1	)	$	(39.3	)

25

The following table shows the reclassifications out of accumulated other comprehensive loss during the three months ended March 31, 2013:

	Amount Reclassified			Affected Line Item in the Statements of Income
Losses on cash flow hedges
Utility commodity derivative contracts	$	0.2		Operating and maintenance expense(1)
Non-regulated commodity derivative contracts	1.1			Nonregulated revenues
Interest rate hedges	0.2			Interest expense
	1.5			Total before tax
	0.6			Tax expense
	0.9			Net of tax
Defined benefit pension plans
Amortization of prior service costs	(0.1		)	(2)
Amortization of actuarial losses	1.1			(2)
	1.0			Total before tax
	0.4			Tax expense
	0.6			Net of tax
Total reclassifications	$	1.5

⁽¹⁾  Changes in the price of natural gas used to support utility operations is not a component of the natural gas costs recovered from customers on a one-for-one basis.

⁽²⁾  These items are included in the computation of net periodic benefit cost. See Note 14, "Employee Benefit Plans," foradditional information.

NOTE 18 — VARIABLE INTEREST ENTITIES

In 2012, ITF formed AMP Trillium LLC as a joint venture with AMP Americas LLC. ITF owns 30% and AMP Americas LLC owns 70% of the joint venture. The joint venture was established to own and operate compressed natural gas fueling stations. The preferred source of capital funding for the joint venture is loans from ITF. We determined that the joint venture is a variable interest entity and that ITF is the primary beneficiary, which requires us to consolidate the assets, liabilities, and statements of income of the joint venture. At March 31, 2013, and December 31, 2012, our variable interests in the joint venture included an insignificant equity investment and insignificant receivables. Our maximum exposure to loss as a result of this joint venture was not significant. The carrying amounts of AMP Trillium LLC assets and liabilities included on our balance sheets were also not significant.

In 2011, ITF formed Integrys PTI CNG Fuels LLC as a joint venture with Paper Transport Inc. ITF and Paper Transport Inc. each own 50% of the joint venture. The joint venture was established to own and operate compressed natural gas fueling stations. The preferred source of capital funding for the joint venture is loans from ITF. We determined that the joint venture is a variable interest entity and that ITF is the primary beneficiary, which requires us to consolidate the assets, liabilities, and statements of income of the joint venture. At March 31, 2013, and December 31, 2012, our variable interests in the joint venture included an insignificant equity investment and insignificant receivables. Our maximum exposure to loss as a result of this joint venture was not significant. The carrying amounts of Integrys PTI CNG Fuels LLC assets and liabilities included on our balance sheets were also not significant.

We have a variable interest in an entity through a power purchase agreement at UPPCO that reimburses an independent power producing entity for coal costs relating to purchased energy. There is no obligation to purchase energy under this agreement. This contract for 17.5 megawatts of capacity expires in 2014. We evaluated this variable interest entity for possible consolidation. We considered which interest holder has the power to direct the activities that most significantly impact the economics of the variable interest entity; this interest holder is considered the primary beneficiary of the entity and is required to consolidate the entity. For a variety of reasons, including qualitative factors such as the length of the remaining term of the contract compared with the remaining life of the plant and the fact that we do not have the power to direct the operations and maintenance of the facility, we determined we are not the primary beneficiary of the variable interest entity. At March 31, 2013, and December 31, 2012, the assets and liabilities on the balance sheets that related to our involvement with this variable interest entity pertained to working capital accounts and represented the amounts we owed for current deliveries of power. We have not guaranteed any debt or provided any equity support, liquidity arrangements, performance guarantees, or other commitments associated with the contract. There is not a significant potential exposure to loss as a result of involvement with the variable interest entity.

We also had a variable interest in Fox Energy Company LLC through a power purchase agreement at WPS that contained a tolling arrangement related to the cost of fuel. In connection with the purchase of Fox Energy Company LLC, WPS paid $50.0 million for the early termination of this 500 megawatt agreement. See Note 4, “Acquisitions,” for more information regarding this purchase. We evaluated this variable interest entity for possible consolidation and determined that consolidation was not required since we were not the primary beneficiary of the variable interest entity. The assets and liabilities on our December 31, 2012 balance sheet that related to our involvement with this variable interest entity pertained to working capital accounts and represented the amounts we owed for current deliveries of power.

26

NOTE 19 — FAIR VALUE

Fair Value Measurements

The following tables show assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:

	March 31, 2013
(Millions)	Level 1		Level 2		Level 3		Total
Assets
Risk Management Assets
Utility Segments
Natural gas contracts	$	1.2	$	10.5	$	—	$	11.7
Financial transmission rights (FTRs)	—		—		1.0		1.0
Petroleum product contracts	0.1		—		—		0.1
Coal contracts	—		—		0.1		0.1
Nonregulated Segments
Natural gas contracts	10.2		21.2		2.9		34.3
Electric contracts	64.0		107.9		13.7		185.6
Total Risk Management Assets	$	75.5	$	139.6	$	17.7	$	232.8
Investment in exchange-traded funds	$	12.4	$	—	$	—	$	12.4
Liabilities
Risk Management Liabilities
Utility Segments
Natural gas contracts	$	—	$	3.8	$	—	$	3.8
FTRs	—		—		0.1		0.1
Coal contracts	—		0.1		4.7		4.8
Nonregulated Segments
Natural gas contracts	9.0		14.8		1.2		25.0
Electric contracts	78.6		70.3		7.6		156.5
Total Risk Management Liabilities	$	87.6	$	89.0	$	13.6	$	190.2

	December 31, 2012
(Millions)	Level 1		Level 2		Level 3		Total
Assets
Risk Management Assets
Utility Segments
Natural gas contracts	$	0.3	$	3.1	$	—	$	3.4
FTRs	—		—		2.1		2.1
Petroleum product contracts	0.2		—		—		0.2
Coal contracts	—		—		2.5		2.5
Nonregulated Segments
Natural gas contracts	21.4		36.4		5.4		63.2
Electric contracts	48.4		61.3		9.6		119.3
Total Risk Management Assets	$	70.3	$	100.8	$	19.6	$	190.7
Investment in exchange-traded funds	$	11.8	$	—	$	—	$	11.8
Liabilities
Risk Management Liabilities
Utility Segments
Natural gas contracts	$	1.1	$	14.1	$	—	$	15.2
FTRs	—		—		0.1		0.1
Coal contracts	—		—		9.0		9.0
Nonregulated Segments
Natural gas contracts	17.7		36.9		1.5		56.1
Electric contracts	54.9		91.1		13.9		159.9
Total Risk Management Liabilities	$	73.7	$	142.1	$	24.5	$	240.3

27

The risk management assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices and interest rates. For more information on derivative instruments, see Note 3, “Risk Management Activities.”

The following tables show net risk management assets (liabilities) transferred between the levels of the fair value hierarchy:

	Nonregulated Segments — Natural Gas Contracts
	Three Months Ended March 31, 2013						Three Months Ended March 31, 2012
(Millions)	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Transfers into Level 1 from	N/A		$	—	$	—	N/A		$	—	$	—
Transfers into Level 2 from	$	—	N/A		—		$	—	N/A		1.3
Transfers into Level 3 from	—		0.2		N/A		—		2.4		N/A

	Nonregulated Segments — Electric Contracts
	Three Months Ended March 31, 2013						Three Months Ended March 31, 2012
(Millions)	Level 1		Level 2		Level 3		Level 1		Level 2			Level 3
Transfers into Level 1 from	N/A		$	—	$	—	N/A		$	—		$	—
Transfers into Level 2 from	$	—	N/A		5.5		$	—	N/A			(0.1		)
Transfers into Level 3 from	—		—		N/A		—		(5.0		)	N/A

Derivatives are transferred between the levels of the fair value hierarchy primarily due to changes in the source of data used to construct price curves as a result of changes in market liquidity.

The significant unobservable inputs used in the valuation that resulted in categorization within Level 3 were as follows at March 31, 2013. The amounts and percentages listed in the table below represent the range of unobservable inputs that individually had a significant impact on the fair value determination and caused a derivative transaction to be classified as Level 3.

	Fair Value (Millions)
	Assets		Liabilities		Valuation Technique	Unobservable Input	Average or Range
Utility Segments
FTRs	$	1.0	$	0.1	Market-based	Forward market prices ($/megawatt-month) (1)	203.72
Coal contracts	0.1		4.7		Market-based	Forward market prices ($/ton) (2)	11.64 — 13.90
Nonregulated Segments
Natural gas contracts	2.9		1.2		Market-based	Forward market prices ($/dekatherm) (3)	(0.08) — 1.99
						Probability of default	11.6% — 51.0%
Electric contracts	13.7		7.6		Market-based	Forward market prices ($/megawatt-hours) (3)	(9.55) — 44.03
						Option volatilities (4)	19.0% — 80.0%

⁽¹⁾  Represents forward market prices developed using historical cleared pricing data from MISO used in the valuation of FTRs.

⁽²⁾  Represents third-party forward market pricing used in the valuation of our coal contracts.

⁽³⁾  Represents unobservable basis spreads developed using historical settled prices that are applied to observable market prices at various natural gas and electric locations, as well as unobservable adjustments made to extend observable market prices beyond the quoted period through the end of the transaction term.

⁽⁴⁾  Represents the range of volatilities used in the valuation of options.

Significant changes in historical settlement prices, forward commodity prices, and option volatilities would result in a directionally similar significant change in fair value. Significant changes in probability of default would result in a significant directionally opposite change in fair value. Changes in the adjustments to prices related to monthly curve shaping would affect fair value differently depending on their direction.

28

The following tables set forth a reconciliation of changes in the fair value of items categorized as Level 3 measurements:

Three Months Ended March 31, 2013	Nonregulated Segments						Utility Segments
(Millions)	Natural Gas			Electric			FTRs			Coal Contracts			Total
Balance at the beginning of the period	$	3.9		$	(4.3	)	$	2.0		$	(6.5	)	$	(4.9	)
Net realized and unrealized (losses) gains included in earnings	(1.5		)	15.1			0.3			—			13.9
Net unrealized (losses) gains recorded as regulatory assets or liabilities	—			—			(0.2		)	3.1			2.9
Purchases	—			0.7			—			—			0.7
Settlements	(0.9		)	0.1			(1.2		)	(1.2		)	(3.2		)
Net transfers into Level 3	0.2			—			—			—			0.2
Net transfers out of Level 3	—			(5.5		)	—			—			(5.5		)
Balance at the end of the period	$	1.7		$	6.1		$	0.9		$	(4.6	)	$	4.1
Net unrealized (losses) gains included in earnings related to instruments still held at the end of the period	$	(1.5	)	$	15.1		$	—		$	—		$	13.6

Three Months Ended March 31, 2012	Nonregulated Segments						Utility Segments
(Millions)	Natural Gas			Electric			FTRs			Coal Contract			Total
Balance at the beginning of the period	$	8.3		$	(11.5	)	$	2.2		$	(6.9	)	$	(7.9	)
Net realized and unrealized gains (losses) included in earnings	4.1			(7.7		)	0.5			—			(3.1		)
Net unrealized gains (losses) recorded as regulatory assets or liabilities	—			—			0.1			(5.8		)	(5.7		)
Purchases	—			1.1			—			—			1.1
Sales	—			—			(0.1		)	—			(0.1		)
Settlements	(2.6		)	1.1			(1.8		)	(0.7		)	(4.0		)
Net transfers into Level 3	2.4			(5.0		)	—			—			(2.6		)
Net transfers out of Level 3	(1.3		)	0.1			—			—			(1.2		)
Balance at the end of the period	$	10.9		$	(21.9	)	$	0.9		$	(13.4	)	$	(23.5	)
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	$	4.1		$	(7.7	)	$	—		$	—		$	(3.6	)

Unrealized gains and losses included in earnings related to Integrys Energy Services’ risk management assets and liabilities are recorded through nonregulated revenue on the statements of income. Realized gains and losses on these same instruments are recorded in nonregulated revenue or nonregulated cost of sales, depending on the nature of the instrument. Unrealized gains and losses on Level 3 derivatives at the utilities are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through utility cost of fuel, natural gas, and purchased power on the statements of income.

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:

	March 31, 2013				December 31, 2012
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	2,223.2	$	2,376.2	$	2,245.2	$	2,425.8
Preferred stock of subsidiary	51.1		61.7		51.1		52.7

The fair values of long-term debt instruments are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. The fair values of preferred stock are estimated based on quoted market prices when available, or by using a perpetual dividend discount model. The fair values of long-term debt instruments and preferred stock are categorized within Level 2 of the fair value hierarchy.

Due to the short-term nature of cash and cash equivalents, accounts receivable, accounts payable, notes payable, and outstanding commercial paper, the carrying amount for each such item approximates fair value.

29

NOTE 20 — ADVERTISING COSTS

Costs associated with certain natural gas and electric direct-response advertising campaigns at Integrys Energy Services were capitalized and reported as other long-term assets on the balance sheets. The capitalized costs result in probable future benefits and were incurred to solicit sales to customers who could be shown to have responded specifically to the advertising. Capitalized direct-response advertising costs, net of accumulated amortization, totaled $4.1 million and $5.5 million as of March 31, 2013, and December 31, 2012, respectively. The asset balances for each of the direct-response advertising cost pools are reviewed quarterly for impairment, and there was no impairment during the three months ended March 31, 2013, and 2012.

Direct-response advertising costs are amortized to operating and maintenance expense over the estimated period of benefit, which is approximately two years. The amortization of direct-response advertising costs was $3.0 million and $1.0 million for the three months ended March 31, 2013, and 2012, respectively.

We expense all advertising costs as incurred, except for those capitalized as direct-response advertising, as discussed above. Other advertising expense was $2.3 million and $1.7 million, for the three months ended March 31, 2013, and 2012, respectively.

NOTE 21 — REGULATORY ENVIRONMENT

Wisconsin

2014 Rates

On March 29, 2013, WPS filed an application with the PSCW to increase retail electric and natural gas rates $71.1 million and $19.0 million, respectively, with rates proposed to be effective January 1, 2014. The filing includes a request for a 10.75% return on common equity and a common equity ratio of 51.11% in WPS's regulatory capital structure. The proposed retail electric rate increase is primarily driven by the purchase and operation of the Fox Energy Center, the completion of a one-time fuel refund to customers in 2013, increased electric transmission costs, and additional construction related to the installation of environmental controls and the improvement of electric reliability. Partially offsetting these increases are lower purchased power capacity costs and a refund to customers resulting from WPS's decoupling mechanism. The proposed retail natural gas rate increase is generally the result of the recovery of amounts related to decoupling, increased costs of inspecting natural gas lines for safety, and general inflation.

2013 Rates

On December 6, 2012, the PSCW issued an order approving a settlement agreement for WPS, effective January 1, 2013. The settlement agreement includes a $28.5 million imputed retail electric rate increase, partially offset by the actual 2012 fuel refund of $20.5 million. The difference between the 2012 fuel refund and the rate increase is being deferred for recovery in a future rate proceeding. As a result, there is no change to customers' 2013 retail electric rates. The settlement agreement also includes a $3.4 million retail natural gas rate decrease, which includes a deferral of $2.4 million of employee benefit costs that will be recovered in a future rate proceeding. The 2013 electric and natural gas rates were subject to downward adjustment based on updated December 31, 2012, pension and benefit cost estimates, which were filed with the PSCW on March 1, 2013. The settlement agreement reflects a 10.30% return on common equity and a common equity ratio of 51.61% in WPS's regulatory capital structure. In addition, WPS was authorized recovery of $5.9 million related to income tax amounts previously expensed due to the Federal Health Care Reform Act. As a result, this amount was recorded as a regulatory asset in 2012 and began being recovered from customers in 2013. The settlement agreement also authorized the recovery of direct Cross State Air Pollution Rule (CSAPR) costs incurred through the end of 2012. Lastly, the settlement agreement also authorized WPS to switch from production tax credits to Section 1603 Grants for the Crane Creek Wind Project.

A new decoupling mechanism for natural gas and electric residential and small commercial and industrial customers was approved as part of the settlement agreement on a pilot basis for 2013. The mechanism is based on total rate case-approved margins, rather than being calculated on a per-customer basis. The mechanism does not cover all customer classes, and it continues to include an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service. Amounts recoverable from or refundable to customers are subject to these caps and are included in rates upon approval in a rate proceeding.

2012 Rates

On December 9, 2011, the PSCW issued a final written order for WPS, effective January 1, 2012. It authorized an electric rate increase of $8.1 million and required a natural gas rate decrease of $7.2 million. The electric rate increase was driven by projected increases in fuel and purchased power costs. However, to the extent that actual fuel and purchased power costs exceeded a 2% price variance from costs included in rates, they were deferred for recovery or refund in a future rate proceeding. The rate order allowed for the netting of the 2010 electric decoupling under-collection with the 2011 electric decoupling over-collection, and reflected reduced contributions to the Focus on Energy Program. The rate order also allowed for the deferral of direct CSAPR compliance costs, including carrying costs.

30

Michigan

MGU Depreciation Case

In January 2013, the Michigan Court of Appeals issued an order reversing the MPSC's 2010 disallowance of $2.5 million associated with the early retirement of certain MGU assets. As a result, a $2.5 million reduction to depreciation expense was recorded in 2013. MGU has modified its depreciation study currently pending before the MPSC to reflect recovery of these previously disallowed costs. The deadline to appeal the Michigan Court of Appeals' order was March 7, 2013.

2012 UPPCO Rates

On December 20, 2011, the MPSC issued an order approving a settlement agreement for UPPCO authorizing a retail electric rate increase of $4.2 million, effective January 1, 2012. The new rates reflect a 10.20% return on common equity and a common equity ratio of 54.90% in UPPCO's regulatory capital structure. The order states that if UPPCO files a rate case in 2013, the earliest effective date for new final rates or self-implemented rates is January 1, 2014. Additionally, the order required UPPCO to terminate its existing decoupling mechanism, effective December 31, 2011, and replace it with a new decoupling mechanism based on total margins, beginning January 1, 2013. The new decoupling mechanism does not cover variations in volumes due to actual weather being different from rate case-assumed weather. It includes an annual 1.5% cap based on distribution revenues approved in the rate case. UPPCO had no decoupling mechanism in place during 2012.

In April 2012, the State of Michigan Court of Appeals ruled in a Detroit Edison proceeding that the MPSC did not have authority to approve electric decoupling mechanisms. This decision was not appealed. As a result of this ruling, UPPCO expensed $1.5 million in the first quarter of 2012 related to electric decoupling amounts previously deferred for regulatory recovery. However, in August 2012, the MPSC issued an order stating it had the authority to approve UPPCO's decoupling mechanism, as UPPCO's decoupling mechanism was authorized pursuant to an MPSC-approved settlement agreement. Therefore, in the third quarter of 2012, UPPCO reversed the $1.5 million previously expensed in the first quarter of 2012.

Illinois

2013 Rate Cases

On July 31, 2012, PGL and NSG filed applications with the ICC to increase retail natural gas rates $78.3 million and $9.8 million, respectively, with rates expected to be effective in July 2013. Both PGL's and NSG's requests reflect a 10.75% return on common equity and a target common equity ratio of 50.00% in their regulatory capital structures. In their briefs, PGL and NSG reflected revised increases of $97.0 million and $9.6 million, respectively, including a revised requested return on common equity of 10.00%. The revised request at PGL was primarily driven by increased costs due to new permitting and restoration requirements, as well as modifications in natural gas main and service pipe installation procedures.

In its reply brief, the ICC Staff recommended rate increases of $12.9 million and $3.4 million for PGL and NSG, respectively, as well as a 9.06% return on common equity for both companies. Their recommendation also included a common equity ratio of 50.43% and 50.32% in PGL's and NSG's regulatory capital structures, respectively. In the Illinois Attorney General's reply brief, it recommended rate increases not to exceed $15.4 million- and $2.6 million for PGL and NSG, respectively, and in its initial brief, adopted the Staff's return on equity recommendations.

On April 26, 2013, the Administrative Law Judges served their proposed order recommending rate increases of $52.0 million and $6.1 million for PGL and NSG, respectively. This reflects a 9.33% return on common equity for both companies. The proposed order included a common equity ratio of 50.43% and 50.32% in PGL's and NSG's regulatory capital structures, respectively.  Exception briefs and replies to the proposed order are due May 9, 2013 and May 16, 2013, respectively. The ICC will issue a final order in this proceeding no later than June 27, 2013.

2012 Rates

On January 10, 2012, the ICC issued a final order authorizing a retail natural gas rate increase of $57.8 million for PGL and $1.9 million for NSG, effective January 21, 2012. The rates for PGL reflected a 9.45% return on common equity and a common equity ratio of 49.00% in PGL's regulatory capital structure. The rates for NSG reflected a 9.45% return on common equity and a common equity ratio of 50.00% in NSG's regulatory capital structure. The rate order also approved a permanent decoupling mechanism.

The Illinois Attorney General appealed to the Illinois Appellate Court (Court) the ICC's authority to approve decoupling and filed a motion to stay the implementation of the permanent decoupling mechanism or make collections subject to refund. In May 2012, the ICC issued a revised amendatory order granting the Illinois Attorney General's motion to make revenues collected under the permanent decoupling mechanism subject to refund. Refunds would have been required if the Court found that the ICC did not have authority to approve decoupling and ordered a refund. As a result, the recovery of amounts related to decoupling in 2012 were uncertain, and PGL and NSG had established offsetting reserves equal to decoupling amounts accrued. In March 2013, the Court issued an opinion that affirmed the ICC's order approving the permanent decoupling mechanism. Therefore, PGL's and NSG's permanent decoupling mechanism is in place for 2013, and decoupling amounts recorded in 2012 and 2013 are expected to be recovered or refunded, absent an adverse decision on appeal at the Illinois Supreme Court. Between April 1, 2013 and December 31, 2013, PGL and NSG expect to recover $14.8 million and $1.7 million, respectively, related to their 2012 decoupling mechanisms.

31

Minnesota

2011 Rates

On July 13, 2012, the MPUC approved a written order for MERC authorizing a retail natural gas rate increase of $11.0 million, effective January 1, 2013. The new rates reflect a 9.70% return on common equity and a common equity ratio of 50.48% in MERC's regulatory capital structure. In addition, the order set recovery of MERC's 2011 test-year pension expense at 2010 levels. The MPUC also approved a decoupling mechanism for MERC that covers residential and small commercial and industrial customers on a three-year trial basis, effective January 1, 2013. The decoupling mechanism does not adjust for variations in volumes resulting from changes in customer count compared to rate case levels. It includes an annual 10% cap based on distribution revenues approved in the rate case. Amounts recoverable from or refundable to customers are subject to this cap.

Federal

Through a series of orders issued by the FERC, Regional Through and Out Rates for transmission service between the MISO and the PJM Interconnection were eliminated effective December 1, 2004. To compensate transmission owners for the revenue they would no longer receive due to this rate elimination, the FERC ordered a transitional pricing mechanism called the Seams Elimination Charge Adjustment (SECA) be put into place. Load-serving entities paid these SECA charges during a 16-month transition period from December 1, 2004, through March 31, 2006.

Integrys Energy Services initially expensed the majority of the total $19.2 million of billings received during the transitional period. The remaining amount was considered probable of recovery due to inconsistencies between the FERC's SECA order and the transmission owners' FERC-ordered compliance filings. Integrys Energy Services protested the FERC’s SECA order, and in August 2006, the Administrative Law Judge hearing the case issued an Initial Decision that was in substantial agreement with all of Integrys Energy Services' positions. In May 2010, the FERC ruled favorably for Integrys Energy Services on two issues, but reversed the rulings of the Initial Decision on nearly every other substantive issue. Integrys Energy Services and numerous other parties filed for rehearing of the FERC's order on the Initial Decision, which the FERC denied on September 30, 2011. The FERC has yet to issue an order on the compliance filings made by the transmission owners. Integrys Energy Services has appealed the adverse FERC decision to the U.S. Court of Appeals for the D.C. Circuit. As a result of the rulings received from the FERC in May 2010, Integrys Energy Services had a $3.8 million receivable recorded at March 31, 2013.

In January 2013, Integrys Energy Services reached a settlement with American Electric Power Service Corporation (AEP), and filed a Joint Stipulation and Agreement ("Settlement Agreement") with the FERC on January 10, 2013. If approved by the FERC, the Settlement Agreement will become effective on the date the FERC's order approving the Settlement Agreement becomes final and nonappealable. The Settlement Agreement provides that AEP would remit to Integrys Energy Services, in complete settlement of the matters at issue, a lump sum payment of $9.5 million within five business days of the effective date of the Settlement Agreement, and within five days of receipt of the lump sum payment, Integrys Energy Services would withdraw its petitions for review filed with the U.S. Court of Appeals for the D.C. Circuit.

NOTE 22 — SEGMENT OF BUSINESS

At March 31, 2013, we reported five segments, which are described below.

• The natural gas utility segment includes the regulated natural gas utility operations of MERC, MGU, NSG, PGL, and WPS.

• The electric utility segment includes the regulated electric utility operations of UPPCO and WPS.

• The electric transmission investment segment includes our approximate 34% ownership interest in ATC. ATC is a federally regulated electric transmission company.

• Integrys Energy Services is a diversified nonregulated retail energy supply and services company that primarily sells electricity and natural gas in deregulated markets. In addition, Integrys Energy Services invests in energy assets with renewable attributes.

• The holding company and other segment includes the operations of the Integrys Energy Group holding company, ITF, and the PELLC holding company, along with any nonutility activities at IBS, MERC, MGU, NSG, PGL, UPPCO, and WPS.

32

The tables below present information related to our reportable segments:

	Regulated Operations											Nonutility and Nonregulated Operations
(Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			Integrys Energy Services		Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Three Months Ended
March 31, 2013
External revenues	$	792.0		$	331.8		$	—	$	1,123.8		$	545.4	$	9.0		$	—		$	1,678.2
Intersegment revenues	1.9			—			—		1.9			0.3		0.4			(2.6		)	—
Depreciation and amortization expense	32.2			21.5			—		53.7			2.7		4.6			(0.1		)	60.9
Earnings from equity method investments	—			—			21.7		21.7			0.2		0.4			—			22.3
Miscellaneous income	0.2			1.6			—		1.8			0.4		7.2			(3.7		)	5.7
Interest expense	12.7			9.1			—		21.8			0.5		10.7			(3.7		)	29.3
Provision (benefit) for income taxes	63.3			16.1			8.3		87.7			27.3		(5.4		)	—			109.6
Net income (loss) from continuing operations	89.8			29.3			13.4		132.5			51.3		(1.6		)	—			182.2
Discontinued operations	—			—			—		—			0.1		6.0			—			6.1
Preferred stock dividends of subsidiary	(0.1		)	(0.7		)	—		(0.8		)	—		—			—			(0.8		)
Net income attributed to common shareholders	89.7			28.6			13.4		131.7			51.4		4.4			—			187.5

	Regulated Operations											Nonutility and Nonregulated Operations
(Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			Integrys Energy Services			Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Three Months Ended
March 31, 2012
External revenues	$	664.0		$	307.0		$	—	$	971.0		$	269.4		$	7.5		$	—		$	1,247.9
Intersegment revenues	1.7			—			—		1.7			0.2			0.7			(2.6		)	—
Depreciation and amortization expense	32.4			22.0			—		54.4			2.3			5.5			(0.1		)	62.1
Earnings from equity method investments	—			—			20.8		20.8			0.1			0.2			—			21.1
Miscellaneous income	0.2			0.1			—		0.3			0.6			5.7			(4.2		)	2.4
Interest expense	12.0			9.2			—		21.2			0.5			12.9			(4.2		)	30.4
Provision (benefit) for income taxes	51.5			10.2			7.5		69.2			(12.3		)	(9.5		)	—			47.4
Net income (loss) from continuing operations	78.7			25.0			13.3		117.0			(19.1		)	0.9			—			98.8
Discontinued operations	—			—			—		—			(1.0		)	1.9			—			0.9
Preferred stock dividends of subsidiary	(0.1		)	(0.7		)	—		(0.8		)	—			—			—			(0.8		)
Net income (loss) attributed to common shareholders	78.6			24.3			13.3		116.2			(20.1		)	2.8			—			98.9

NOTE 23 — NEW ACCOUNTING PRONOUNCEMENTS

Recently Adopted Accounting Guidance

Accounting Standards Update (ASU) 2013-02, "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income," was issued in February 2013. This guidance requires disclosure of amounts reclassified out of accumulated other comprehensive income by component. Significant amounts are required to be presented by the respective line items of net income or should be cross-referenced to other disclosures. These disclosures may be presented on the income statement or in the notes to the financial statements. Adoption of this guidance resulted in the addition of Note 17, "Accumulated Other Comprehensive Loss."

ASU 2011-11, "Disclosures about Offsetting Assets and Liabilities," was issued in December 2011. The guidance requires enhanced disclosures about offsetting and related arrangements. ASU 2013-01, "Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities," was issued in January 2013. This guidance clarifies that the scope of ASU 2011-11 applies to certain derivatives included in the Derivatives and Hedging Topic of the FASB ASC. Adoption of the guidance resulted in new disclosures in Note 3, "Risk Management Activities."

33

ASU 2012-02, "Testing Indefinite-Lived Intangible Assets for Impairment," was issued in July 2012. This guidance gives companies an option to first perform a qualitative assessment to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired. If a company concludes that this is the case, the fair value of the indefinite-lived intangible asset must be determined, and a quantitative impairment test is required. Otherwise, a company can bypass the quantitative impairment test. Adoption of this guidance did not have an impact on our financial statements.

34

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

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, 2012.

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 2013 Over 2012
(Millions, except per share amounts)	2013		2012
Natural gas utility operations	$	89.7	$	78.6		14.1	%
Electric utility operations	28.6		24.3			17.7	%
Electric transmission investment	13.4		13.3			0.8	%
Integrys Energy Services’ operations	51.4		(20.1		)	N/A
Holding company and other operations	4.4		2.8			57.1	%
Net income attributed to common shareholders	$	187.5	$	98.9		89.6	%
Basic earnings per share	$	2.38	$	1.26		88.9	%
Diluted earnings per share	$	2.37	$	1.25		89.6	%
Average shares of common stock
Basic	78.7		78.6			0.1	%
Diluted	79.3		79.2			0.1	%

First Quarter 2013 Compared with First Quarter 2012

Our 2013 first quarter earnings were $187.5 million, compared with 2012 first quarter earnings of $98.9 million. The $88.6 million increase in earnings was driven by:

• A $66.8 million after-tax non-cash increase in Integrys Energy Services’ margins related to derivative and inventory fair value adjustments.

• A $9.9 million after-tax increase in natural gas utility margins due to the reversal of reserves recorded in 2012 against decoupling accruals at PGL and NSG. In March 2013, the Illinois Appellate Court affirmed the ICC's authority to approve the permanent decoupling mechanisms. See Note 21, "Regulatory Environment," for more information.

• A $6.4 million after-tax increase in natural gas utility margins due to a net increase in sales volumes driven by a return to more normal weather during 2013 compared with unusually warm weather in 2012, net of decoupling.

• A $5.2 million increase in income from discontinued operations. See Note 5, "Discontinued Operations," for more information.

35

Regulated Natural Gas Utility Segment Operations

	Three Months Ended March 31						Change in 2013 Over 2012
(Millions, except heating degree days)	2013			2012
Revenues	$	793.9		$	665.7		19.3	%
Purchased natural gas costs	424.1			346.5			22.4	%
Margins	369.8			319.2			15.9	%
Operating and maintenance expense	162.1			135.3			19.8	%
Depreciation and amortization expense	32.2			32.4			(0.6	)%
Taxes other than income taxes	9.9			9.5			4.2	%
Operating income	165.6			142.0			16.6	%
Miscellaneous income	0.2			0.2			—	%
Interest expense	(12.7		)	(12.0		)	5.8	%
Other expense	(12.5		)	(11.8		)	5.9	%
Income before taxes	$	153.1		$	130.2		17.6	%
Retail throughput in therms
Residential	775.9			606.4			28.0	%
Commercial and industrial	236.8			183.4			29.1	%
Other	20.0			18.7			7.0	%
Total retail throughput in therms	1,032.7			808.5			27.7	%
Transport throughput in therms
Residential	111.3			87.1			27.8	%
Commercial and industrial	551.6			476.7			15.7	%
Total transport throughput in therms	662.9			563.8			17.6	%
Total throughput in therms	1,695.6			1,372.3			23.6	%
Weather
Average heating degree days	3,506			2,589			35.4	%

First Quarter 2013 Compared with First Quarter 2012

Margins

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 we pass through prudently incurred natural gas commodity costs to our customers in current rates. There was an approximate 4% decrease in the average per-unit cost of natural gas sold during the first quarter of 2013, which had no impact on margins.

Regulated natural gas utility segment margins increased $50.6 million, driven by:

• An approximate $28 million net increase in margins, including the impact of decoupling, due to a 23.6% increase in volumes sold in the first quarter of 2013.

◦ A return to more normal weather during 2013, compared with unusually warm weather in 2012, drove an approximate $43 million increase in margins. Heating degree days increased 35.4%.

◦ Lower sales volumes excluding the impact of weather resulted in an approximate $1 million decrease in margins. Sales volumes were slightly lower due to lower use per customer.

◦ Decoupling impacts at certain natural gas utilities partially offset the net positive impact of volumes discussed above and decreased margins approximately $14 million. Decoupling does not cover all jurisdictions or customer classes. In addition, this decrease is net of the $17 million positive impact of the 2013 reversal of reserves that had been recorded in 2012 against decoupling accruals at PGL and NSG. See Note 21, "Regulatory Environment," for more information.

36

• An approximate $22 million net increase in margins related to certain riders at PGL and NSG. This increase was offset by an equal increase in operating expenses, resulting in no impact on earnings.

◦ PGL and NSG recovered approximately $13 million more for environmental cleanup costs at their former manufactured gas plant sites related to an increase in remediation activity during 2013. See Note 12, "Commitment and Contingencies," for more information about the manufactured gas plant sites.

◦ PGL and NSG billed approximately $9 million more to customers for energy efficiency programs in 2013.

• An approximate $1 million net increase in margins due to rate orders. See Note 21, "Regulatory Environment," for more information.

◦ The rate increases at PGL and NSG, effective January 21, 2012, and other impacts of rate design, had an approximate $3 million positive impact on margins.

◦ A reduction in rates at WPS, effective January 1, 2013, resulted in an approximate $3 million negative impact on margins.

◦ MERC had an approximate $1 million increase in margins primarily driven by the impact of a rate order from the MPUC finalized in January 2013. Customer refunds were accrued in the first quarter of 2012 as a result of 2011 interim rates that were in effect.

Operating Income

Operating income at the regulated natural gas utility segment increased $23.6 million. This increase was driven by the $50.6 million increase in margins discussed above, partially offset by a $27.0 million increase in operating expenses.

The increase in operating expenses was primarily related to:

• An approximate $22 million net increase at PGL and NSG driven by higher amortization of regulatory assets related to environmental cleanup costs for manufactured gas plant sites and an increase in regulatory liabilities related to energy efficiency programs. Margins increased by an equal amount, resulting in no impact on earnings.

• A $4.6 million increase in employee benefit costs. The increase was partially due to higher pension expense, primarily at PGL, driven by a lower discount rate used in 2013. The lower discount rate did not significantly impact the other natural gas utilities due to an increase in contributions to those plans in prior years, which increased plan assets. Amortization of negative investment returns from prior years also increased pension expense in 2013.

The increase in operating expenses was partially offset by a $0.2 million decrease in depreciation and amortization expense. The decrease was driven by a $2.5 million reduction in expense at MGU. In January 2013, the Michigan Court of Appeals issued an order reversing the MPSC's previously ordered disallowance of $2.5 million associated with the early retirement of certain MGU assets in 2010. See Note 21, "Regulatory Environment," for more information. This decrease was partially offset by an increase in depreciation and amortization expense resulting from increased investment in property and equipment, primarily driven by the AMRP at PGL.

37

Regulated Electric Utility Segment Operations

	Three Months Ended March 31						Change in 2013 Over 2012
(Millions, except degree days)	2013			2012
Revenues	$	331.8		$	307.0		8.1	%
Fuel and purchased power costs	143.2			127.5			12.3	%
Margins	188.6			179.5			5.1	%
Operating and maintenance expense	101.4			100.3			1.1	%
Depreciation and amortization expense	21.5			22.0			(2.3	)%
Taxes other than income taxes	12.8			12.9			(0.8	)%
Operating income	52.9			44.3			19.4	%
Miscellaneous income	1.6			0.1			1,500.0	%
Interest expense	(9.1		)	(9.2		)	(1.1	)%
Other expense	(7.5		)	(9.1		)	(17.6	)%
Income before taxes	$	45.4		$	35.2		29.0	%
Sales in kilowatt-hours
Residential	823.8			775.2			6.3	%
Commercial and industrial	2,072.0			2,087.8			(0.8	)%
Wholesale	1,046.6			1,023.5			2.3	%
Other	10.7			10.9			(1.8	)%
Total sales in kilowatt-hours	3,953.1			3,897.4			1.4	%
Weather
WPS:
Heating degree days	3,803			2,864			32.8	%
Cooling degree days	—			11			(100.0	)%
UPPCO:
Heating degree days	4,087			3,282			24.5	%

First Quarter 2013 Compared with First Quarter 2012

Margins

Electric margins are defined as electric 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 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.

Regulated electric utility segment margins increased $9.1 million, driven by:

• An approximate $5 million increase in margins due to a retail electric rate increase at WPS, effective January 1, 2013. For more information on the WPS 2013 rate order, see Note 21, "Regulatory Environment."

• An approximate $4 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 primarily due to a 6.3% increase in sales volumes to residential customers. The quarter-over-quarter impact of decoupling does not directly correlate with the quarter-over-quarter impact of the change in sales volumes, as WPS's decoupling mechanism was changed in 2013, and UPPCO did not have decoupling in 2012. See Note 21, "Regulatory Environment," for more information.

• A $1.5 million increase in margins due to the quarter-over-quarter impact of the write-off of UPPCO’s net regulatory asset related to its 2010 and 2011 decoupling deferrals in the first quarter of 2012. The write-off was reversed in the third quarter of 2012.

• Partially offsetting these increases was an approximate $2 million quarter-over-quarter decrease in margins because WPS fuel costs not included in the fuel window were lower than rate case-approved amounts in 2012.

38

Operating Income

Operating income at the regulated electric utility segment increased $8.6 million. The increase was driven by the $9.1 million increase in margins discussed above, partially offset by a $0.5 million increase in operating expenses. The increase in operating expenses was driven by:

• A $2.2 million increase in employee benefit related expenses, and

• A $2.0 million increase in electric transmission expense.

These increased expenses were partially offset by:

• The $1.8 million positive impact of the deferral of employee benefit costs that will be recovered in a future rate proceeding as a result of the WPS 2013 rate order.

• A $1.2 million decrease in depreciation expense primarily due to a reduction in the depreciable basis of WPS's Crane Creek Wind Project. The reduction is the result of WPS's election to claim a Section 1603 Grant for the project in lieu of production tax credits.

• A $1.0 million decrease in maintenance expense, mainly due to fewer storms in WPS's service territories in 2013 compared to 2012.

Other Expense

Other expense decreased $1.6 million, driven by an increase in AFUDC, primarily related to environmental compliance projects at the Columbia plant.

Electric Transmission Investment Segment Operations

	Three Months Ended March 31				Change in 2013 Over 2012
(Millions)	2013		2012
Earnings from equity method investments	$	21.7	$	20.8	4.3	%

First Quarter 2013 Compared with First Quarter 2012

Earnings from Equity Method Investments

Earnings from equity method investments at the electric transmission investment segment increased $0.9 million in the first quarter of 2013. 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.

39

Integrys Energy Services Nonregulated Segment Operations

While sustained low commodity prices, capital costs, and market volatility have led to competitive pressure on per-unit margins, Integrys Energy Services has been able to take advantage of continued growth opportunities in certain markets by increasing volumes delivered and contracted for future delivery. Delivered electric and natural gas volumes have grown by approximately 48% and 28%, respectively, when comparing the three months ended March 31, 2013, and 2012. In addition, Integrys Energy Services' electric and natural gas volumes for future delivery have grown by approximately 33% and 32%, respectively, when comparing the future contracted volumes at March 31, 2013 to March 31, 2012.

	Three Months Ended March 31						Change in 2013 Over 2012
(Millions, except natural gas sales volumes)	2013			2012
Revenues	$	545.7		$	269.6		102.4	%
Cost of sales	430.7			270.1			59.5	%
Margins	115.0			(0.5		)	N/A
Margin Detail
Realized retail electric margins	23.9			16.9			41.4	%
Realized wholesale electric margins  (1)	—			(0.6		)	(100.0	)%
Realized renewable energy asset margins	3.0			2.6			15.4	%
Fair value accounting adjustments	62.7			(42.7		)	N/A
Electric and renewable energy asset margins	89.6			(23.8		)	N/A
Realized retail natural gas margins	18.9			23.5			(19.6	)%
Realized wholesale natural gas margins (1)	0.2			(0.6		)	N/A
Lower-of-cost-or-market inventory adjustments	4.0			1.6			150.0	%
Fair value accounting adjustments	2.3			(1.2		)	N/A
Natural gas margins	25.4			23.3			9.0	%
Operating and maintenance expense	32.8			27.5			19.3	%
Depreciation and amortization expense	2.7			2.3			17.4	%
Taxes other than income taxes	1.0			1.3			(23.1	)%
Operating income (loss)	78.5			(31.6		)	N/A
Earnings from equity method investments	0.2			0.1			100.0	%
Miscellaneous income	0.4			0.6			(33.3	)%
Interest expense	(0.5		)	(0.5		)	—	%
Other income	0.1			0.2			(50.0	)%
Income (loss) before taxes	$	78.6		$	(31.4	)	N/A
Physically settled volumes
Retail electric sales volumes in kwh	4,318.2			2,918.9			47.9	%
Wholesale assets and distributed solar electric sales volumes in kwh (2)	18.0			22.2			(18.9	)%
Retail natural gas sales volumes in bcf	50.7			39.6			28.0	%

kwh — kilowatt-hours

bcf — billion cubic feet 

⁽¹⁾  Realized wholesale activity relates to remaining contracts for which offsetting positions were entered into.

⁽²⁾  The volumes related to the remaining wholesale electric contracts are not significant.

First Quarter 2013 Compared with First Quarter 2012

Revenues

Integrys Energy Services’ revenues increased $276.1 million, primarily driven by higher retail commodity sales volumes and higher average commodity prices.

40

Margins

Integrys Energy Services’ margins increased $115.5 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 increased $7.0 million, primarily driven by higher sales volumes, partially offset by continued competitive pressure on per-unit margins.

Realized renewable energy asset margins

Realized renewable energy asset margins increased $0.4 million. The increase was primarily driven by continued investment in solar energy projects.

Fair value accounting adjustments

Derivative accounting rules impact Integrys Energy Services’ margins. Fair value adjustments caused a $105.4 million increase 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 decreased $4.6 million. The decrease was primarily driven by continued competitive pressure on per-unit margins. In the first quarter of 2013, there were also fewer opportunities to take advantage of natural gas price volatility and changes in market prices for natural gas storage and transportation capacity. These decreases were partially offset by higher sales volumes.

Inventory accounting adjustments

Integrys Energy Services’ 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 increase in margins from inventory adjustments was driven by lower write-downs.

Fair value accounting adjustments

Derivative accounting rules impact Integrys Energy Services’ margins. Fair value adjustments caused a $3.5 million increase in natural gas margins quarter over quarter. These adjustments primarily relate to physical and financial contracts used to reduce price risk for supply, storage, and transportation associated with natural gas sales contracts. These adjustments will reverse in future periods as contracts settle.

Operating Income (Loss)

Integrys Energy Services’ operating income was $78.5 million in 2013 compared with an operating loss of $31.6 million in 2012. The main driver of the increase in operating income was the $115.5 million increase in margins discussed above, partially offset by a $5.4 million increase in operating expenses, driven by:

• A $4.5 million increase in professional fees, primarily related to the expansion of the residential and small commercial customer segment.

• A $1.9 million increase in payroll and employee benefit expenses.

41

Holding Company and Other Segment Operations

	Three Months Ended March 31						Change in 2013 Over 2012
(Millions)	2013			2012
Operating loss	$	(3.9	)	$	(1.6	)	143.8	%
Other expense	(3.1		)	(7.0		)	(55.7	)%
Net loss before taxes	$	(7.0	)	$	(8.6	)	(18.6	)%

First Quarter 2013 Compared with First Quarter 2012

Operating Loss

Operating loss at the holding company and other segment increased $2.3 million in 2013. The increase was driven primarily by increased operating losses at ITF.

Other Expense

Other expense at the holding company and other segment decreased $3.9 million in 2013. The decrease was driven by tax credits recorded at ITF in 2013 as a result of the American Taxpayer Relief Act of 2012. In addition, interest expense on long-term debt decreased, driven by lower average outstanding long-term debt in 2013.

Provision for Income Taxes

	Three Months Ended March 31
	2013		2012
Effective Tax Rate	37.6	%	32.4	%

First Quarter 2013 Compared with First Quarter 2012

Our effective tax rate increased in the first quarter of 2013. In the fourth quarter of 2012, we elected to claim and subsequently received a Section 1603 Grant for WPS's Crane Creek Wind Project in lieu of production tax credits (PTCs). As a result, we no longer claim wind PTCs on any of our qualifying facilities. In the first quarter of 2012, our effective tax rate was lowered by the effective settlement of certain state income tax examinations and a remeasurement of uncertain tax positions included in our liability for unrecognized tax benefits. We decreased our provision for income taxes $5.2 million in 2012, primarily related to the effective settlement and remeasurement of these positions.

Discontinued Operations

	Three Months Ended March 31				Change in 2013 Over 2012
(Millions)	2013		2012
Discontinued operations, net of tax	$	6.1	$	0.9	577.8	%

First Quarter 2013 Compared with First Quarter 2012

Income from discontinued operations, net of tax, increased $5.2 million in 2013. 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. Income from discontinued operations also increased from recognition of a $1.0 million gain on sale at closing related to Beaver Falls and Syracuse in the first quarter of 2013. See Note 5, “Discontinued Operations,” for more information.

LIQUIDITY AND CAPITAL RESOURCES

We believe we have adequate resources to fund ongoing operations and future capital expenditures. These resources include our 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.

42

Operating Cash Flows

During the three months ended March 31, 2013, net cash provided by operating activities was $319.6 million, compared with $224.8 million for the same period in 2012. The $94.8 millionincrease in net cash provided by operating activities was largely driven by:

• A $183.0 million decrease in contributions to pension and other postretirement benefit plans.

• The $29.1 million quarter-over-quarter positive impact primarily related to Integrys Energy Services' collateral on deposit with brokers, mainly due to higher forward prices of natural gas and electricity.

Partially offsetting these increases were the following:

• WPS paid $50.0 million in 2013 for the early termination of a tolling agreement in connection with the purchase of Fox Energy Company LLC.

• A $35.4 million quarter-over-quarter decrease in cash at PGL and NSG due to natural gas cost under-collections from customers in 2013 versus natural gas cost over-collections from customers in 2012. The quarter-over-quarter change was driven by higher natural gas prices in 2013.

• Cash received from income taxes decreased $32.2 million primarily due to refunds received in 2012 related to prior year amended tax returns.

Investing Cash Flows

Net cash used for investing activities was $473.2 million during the three months ended March 31, 2013, compared with $136.6 million for the same period in 2012. The $336.6 million increase 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 additional information regarding this acquisition. Also contributing to the increase was a $24.0 million increase in cash used for other capital expenditures (discussed below). These increases in net cash used were partially offset by the $69.0 million positive impact from the receipt of a Section 1603 Grant for the Crane Creek Wind Project in 2013.

Capital Expenditures

Capital expenditures by business segment for the three months ended March 31 were as follows:

Reportable Segment (millions)	2013		2012		Change
Natural gas utility	$	85.8	$	78.9	$	6.9
Electric utility	439.9		30.8		409.1
Integrys Energy Services	3.4		8.2		(4.8		)
Holding company and other	9.5		5.1		4.4
Integrys Energy Group consolidated	$	538.6	$	123.0	$	415.6

The increase in capital expenditures at the electric utility segment was primarily due to WPS's purchase of the Fox Energy Center in 2013 and an increase in expenditures related to environmental compliance projects at the Columbia plant.

Financing Cash Flows

Net cash provided by financing activities was $197.2 million during the three months ended March 31, 2013, compared with $74.9 million of net cash used for financing activities for the same period in 2012. The $272.1 million quarter-over-quarter positive impact from financing activities was primarily due to WPS borrowing $200.0 million under its term credit facility in 2013 to finance the acquisition of Fox Energy Company LLC. Also contributing to the increase was a $71.8 million increase in net short-term borrowings.

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 02/05/2013	Issuing 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."

For information on the issuance and redemption of long-term debt in 2013, see Note 10, "Long-Term Debt."

43

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
Credit facility	N/A	Baa1
Junior subordinated notes	BBB	Baa2
WPS
Issuer credit rating	A-	A2
First mortgage bonds	N/A	Aa3
Senior secured debt	A	Aa3
Preferred stock	BBB	Baa1
Commercial paper	A-2	P-1
Credit facility	N/A	A2
PGL
Issuer credit rating	A-	A3
Senior secured debt	A	A1
Commercial paper	A-2	P-2
NSG
Issuer credit rating	A-	A3
Senior secured debt	A	A1

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 February 15, 2013, Standard & Poor's raised PGL's senior secured debt rating to "A" from "A-." PGL's revised rating reflects Standard & Poor's revision to its methodology for assigning recovery ratings for senior bonds secured by utility real property.

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. In addition, the 2012 cash flows also include the operations of WPS Westwood Generation, LLC. See Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations – Discontinued Operations," and Note 5, "Discontinued Operations," for more information.

44

Future Capital Requirements and Resources

Contractual Obligations

The following table shows our contractual obligations as of March 31, 2013, including those of our subsidiaries.

			Payments Due By Period
(Millions)	Total Amounts Committed		2013		2014 to 2015		2016 to 2017		2018 and Later Years
Long-term debt principal and interest payments (1)	$	3,379.9	$	369.5	$	403.2	$	632.5	$	1,974.7
Operating lease obligations	91.7		6.4		11.8		12.3		61.2
Energy and transportation purchase obligations (2)	2,629.1		770.4		776.7		283.0		799.0
Purchase orders (3)	713.5		705.2		3.3		0.8		4.2
Capital contributions to equity method investment	5.1		5.1		—		—		—
Pension and other postretirement funding obligations (4)	538.4		37.5		170.1		60.8		270.0
Uncertain tax positions	0.3		0.3		—		—		—
Total contractual cash obligations	$	7,358.0	$	1,894.4	$	1,365.1	$	989.4	$	3,109.1

⁽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 Integrys Energy Services 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 2018.

The table above does not reflect estimated future payments related to the manufactured gas plant remediation liability of $639.6 million at March 31, 2013, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 12, “Commitments and Contingencies,” for more information about environmental liabilities. The table also does not reflect estimated future payments for the March 31, 2013 liability of $3.6 million related to unrecognized tax benefits, as the amount and timing of payments are uncertain. See Note 11, “Income Taxes,” for more information about unrecognized tax benefits.

45

Capital Requirements

As of March 31, 2013, our capital expenditures by segment for 2013 through 2015 were expected to be as follows:

(Millions)
Natural Gas Utility
Distribution projects and underground storage facilities	$	1,073
Other projects	70
Electric Utility
Environmental projects *	419
Acquisition of Fox Energy Center	392
Distribution and energy supply operations projects	347
Other projects	57
Integrys Energy Services
Renewable energy and other projects	145
Holding Company and Other
Compressed natural gas fueling stations	158
Corporate or shared services software and infrastructure projects	152
Repairs and safety measures at nonutility hydroelectric facilities	3
Total capital expenditures	$	2,816

* Includes $270.2 million related to the installation of ReACT^TM emission control technology at Weston 3 and $127.8 million related to the installation of scrubbers at the Columbia plant.

We expect to provide capital contributions to ATC (not included in the above table) of approximately $61 million from 2013 through 2015.

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 policies to hedge the impact of volatile commodity prices, and makes decisions regarding capital requirements in order to manage the liquidity and capital resource needs of the business segments. We plan to meet our capital requirements for the period 2013 through 2015 primarily through internally generated funds (net of forecasted dividend payments) 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 $500.0 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, 2013, 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. See Note 9, “Short-Term Debt and Lines of Credit,” for more information on credit facilities and other short-term credit agreements. See Note 10, “Long-Term Debt,” for more information on long-term debt.

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 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 16, "Common Equity,"for more information on dividend restrictions.

Other Future Considerations

Decoupling

The Illinois Attorney General had appealed the ICC's authority to approve PGL's and NSG's permanent decoupling mechanism. As a result, revenues collected under this mechanism are 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.

46

Therefore, PGL's and NSG's permanent decoupling mechanism is in place for 2013. Decoupling amounts recorded in 2012 and 2013 are expected to be recovered or refunded, absent an adverse decision on appeal at the Illinois Supreme Court.

See Note 21, "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. The EPA has not committed to a schedule for proposing performance standards for existing units.

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 the majority 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. Significant rulings essential to its framework are now becoming effective for certain companies. Since some of these final rules are being challenged in court, it is difficult to predict how they will ultimately affect us. Certain provisions of the Dodd-Frank Act relating to derivatives could increase capital and/or collateral requirements. We continue to monitor developments related to this act and their potential impacts on our future financial results. At this time, we are making the necessary system and process changes to comply with the known rules. 

Federal Tax Law Changes

In January 2013, President Obama signed into law the American Taxpayer Relief Act of 2012. This act extends 50% bonus tax depreciation through 2013 for most capital expenditures. This bonus tax depreciation extension is anticipated to generate future cash flows in excess of approximately $101 million through 2015.

Illinois Natural Gas Formula Rates

In February 2013, Senate Bill 1665 and House Bill 2414, The Natural Gas Modernization, Public Safety and Jobs Act, were introduced in the Illinois General Assembly. This act would allow certain natural gas utilities, including PGL and NSG, to file performance-based formula rate tariffs for setting rates, including a pre-defined return on equity based on U.S. Treasury Bond rates, and bill impact caps. The timing and outcome of this act is currently unknown.

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, 2012, are still current and that there have been no significant changes.

47

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We have potential market risk exposure related to commodity price risk, interest rate risk, and equity return and principal preservation risk. We are also exposed to other significant risks due to the nature of our subsidiaries’ businesses and the environment in which we operate. We have risk management policies in place to monitor and assist in controlling these risks, and we use derivative and other instruments to manage some of these exposures, as further described below.

Commodity Price Risk

To measure commodity price risk exposure, we employ a number of controls and processes, including a value-at-risk (VaR) analysis of certain of our exposures. Integrys Energy Services’ VaR is calculated using nondiscounted positions with a delta-normal approximation based on a one-day holding period and a 95% confidence level, as well as a ten-day holding period and 99% confidence level. For further explanation of our VaR calculation, see our 2012 Annual Report on Form 10-K.

The VaR for Integrys Energy Services’ open commodity positions at a 95% confidence level with a one-day holding period is presented in the following table:

(Millions)	2013		2012
As of March 31	$	0.2	$	0.1
Average for 12 months ended March 31	0.1		0.1
High for 12 months ended March 31	0.2		0.2
Low for 12 months ended March 31	0.1		0.1

The VaR for Integrys Energy Services’ open commodity positions at a 99% confidence level with a ten-day holding period is presented below:

(Millions)	2013		2012
As of March 31	$	0.7	$	0.4
Average for 12 months ended March 31	0.6		0.5
High for 12 months ended March 31	0.7		0.7
Low for 12 months ended March 31	0.4		0.4

The average, high, and low amounts were computed using the VaR amounts at each of the four quarter ends.

Interest Rate Risk

We are exposed to interest rate risk resulting from our short-term borrowings and projected near-term debt financing needs. We manage exposure to interest rate risk by limiting the amount of variable rate obligations and continually monitoring the effects of market changes on interest rates. When it is advantageous to do so, we enter into long-term fixed rate debt. We may also enter into derivative financial instruments, such as swaps, to mitigate interest rate exposure.

Based on the variable rate debt outstanding at March 31, 2013, a hypothetical increase in market interest rates of 100 basis points would have increased annual interest expense by $7.6 million. Comparatively, based on the variable rate debt outstanding at March 31, 2012, an increase in interest rates of 100 basis points would have increased annual interest expense by $3.3 million. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.

Other than the above-mentioned changes, our market risks have not changed materially from the market risks reported in our 2012 Annual Report on Form 10-K.

48

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of Integrys Energy Group's disclosure controls and procedures (as defined by Securities Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based upon that evaluation, management, including our Chief Executive Officer and Chief Financial Officer, has concluded that Integrys Energy Group's disclosure controls and procedures were effective as of the end of the period covered by this report.

Changes in Internal Control

There were no changes in our internal control over financial reporting (as defined by Securities Exchange Act Rules 13a-15(f) and 15d-15(f)) during the quarter ended March 31, 2013, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

49

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For information on material legal proceedings and matters, see Note 12, “Commitments and Contingencies.”

Item 1A. Risk Factors

There were no material changes in the risk factors previously disclosed in Part I, Item 1A of our 2012 Annual Report on Form 10-K, which was filed with the SEC on March 1, 2013.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Dividend Restrictions

We are a holding company and our ability to pay dividends is largely dependent upon the ability of our subsidiaries to make payments to us in the form of dividends or otherwise. For information regarding restrictions on the ability of our subsidiaries to pay us dividends, see Note 16, “Common Equity.”

Issuer Purchases of Equity Securities

As of February 5, 2013, we began issuing new shares of common stock to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans. Prior to this date, shares were purchased in the open market to meet the requirements of these plans. The following table provides a summary of common stock purchases for the three months ended March 31, 2013:

Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
01/01/13 — 01/31/13 *	15,005	$	54.16	—	—
02/01/13 — 02/28/13 *	6,405	55.39		—	—
03/01/13 — 03/31/13	—	—		—	—
Total	21,410	$	54.53	—	—

* Represents shares of common stock purchased in the open market by American Stock Transfer & Trust Company to provide shares of common stock to participants in the Stock Investment Plan and to satisfy obligations under various stock-based employee benefit and compensation plans.

Item 6. Exhibits

The documents listed in the Exhibit Index are attached as exhibits or incorporated by reference herein.

50

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant, Integrys Energy Group, Inc., has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	INTEGRYS ENERGY GROUP, INC.
	(Registrant)
Date: May 1, 2013	/s/ Linda M. Kallas
	Linda M. Kallas
	Vice President and Corporate Controller
	(Duly Authorized Officer and Chief Accounting Officer)

51

INTEGRYS ENERGY GROUP

EXHIBIT INDEX TO FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2013

Exhibit No.	Description
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Integrys Energy Group, Inc.
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Integrys Energy Group, Inc.
32	Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for Integrys Energy Group, Inc.
101	Financial statements from the Quarterly Report on Form 10-Q of Integrys Energy Group, Inc. for the quarter ended March 31, 2013, formatted in eXtensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Income, (ii) the Condensed Consolidated Statements of Comprehensive Income, (iii) the Condensed Consolidated Balance Sheets, (iv) the Condensed Consolidated Statements of Cash Flows, (v) the Condensed Notes To Financial Statements, and (vi) document and entity information.

52

EX-31.1

Exhibit 31.1

Certification of Chief Executive Officer

Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a)

or 15d-14(a) under the Securities Exchange Act of 1934

I, Charles A. Schrock, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Integrys Energy Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an Annual Report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	May 1, 2013	/s/ Charles A. Schrock
		Charles A. Schrock
		Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

Certification of Chief Financial Officer

Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a)

or 15d-14(a) under the Securities Exchange Act of 1934

I, James F. Schott, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Integrys Energy Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an Annual Report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	May 1, 2013	/s/ James F. Schott
		James F. Schott
		Vice President and Chief Financial Officer

EX-32

Exhibit 32

Written Statement of the Chief Executive Officer and Chief Financial Officer

Pursuant to 18 U.S.C. Section 1350

Solely for the purposes of complying with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, we, the undersigned Chief Executive Officer and Chief Financial Officer of Integrys Energy Group, Inc. (the "Company"), hereby certify, based on our knowledge, that the Quarterly Report on Form 10-Q of the Company for the quarter ended March 31, 2013 (the "Report") fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and that information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Charles A. Schrock

Charles A. Schrock

Chairman, President and Chief Executive Officer

/s/ James F. Schott

James F. Schott

Vice President and Chief Financial Officer

Date:  May 1, 2013

This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by Integrys Energy Group, Inc. for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

A signed original of this written statement required by Section 906 has been provided to Integrys Energy Group, Inc. and will be retained by Integrys Energy Group, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

XML

INCOME TAXES (Tables)

3 Months Ended

Mar. 31, 2013

INCOME TAXES

Schedule of effective tax rates

	Three Months Ended March 31
	2013		2012
Effective Tax Rate	37.6	%	32.4	%

XML

ACQUISITIONS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		0 Months Ended
	Mar. 31, 2013 MW	Mar. 31, 2013 Fox Energy Company, LLC WPS MW	May 31, 2013 Compass Energy Services, Inc. Integrys Energy Services	May 31, 2013 Compass Energy Services, Inc. Integrys Energy Services Minimum	May 31, 2013 Compass Energy Services, Inc. Integrys Energy Services Maximum
Acquisitions
Cost of acquired entity		$ 391.6
Capacity of Fox Energy Center (in megawatts)		593
Contracted capacity under tolling arrangement (in megawatts)	17.5	500
Contract termination fee related to tolling arrangement	(50.0)	50.0
Assets acquired
Inventories		3.0
Other current assets		0.6
Property, plant, and equipment		374.4
Other long-term assets		15.6
Total assets acquired		393.6
Liabilities assumed
Accounts payable		2.0
Total liabilities assumed		2.0
Initial cash payment			12.0
Additional cash consideration payable based upon the financial performance of acquiree				$ 3.0	$ 8.0
Period of financial performance of acquiree as basis for contingent consideration			5 years

XML

CASH AND CASH EQUIVALENTS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Supplemental disclosure of statements of cash flows
Cash paid for interest	$ 4.8	$ 8.9
Cash received for income taxes	(1.0)	(33.2)
Decrease in cash received for income taxes	32.2
Significant noncash transactions
Construction costs funded through accounts payable	59.8	50.2
Equity issued for stock-based compensation plans	18.7
Equity issued for reinvested dividends	3.0
Risk management asset related to sale of Beaver Falls and Syracuse	$ 6.8

XML

STOCK-BASED COMPENSATION (Details 2) (Stock Options, USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Stock Options
Stock based compensation
Period of historical volatility used to estimate expected volatility	10 years
Weighted-average fair values per stock option along with the assumptions incorporated into the valuation models
Weighted-average fair value per option (in dollars per share)	$ 6.03
Expected term	5 years
Risk-free interest rate, (as a percent)	0.18%
Risk-free interest rate, (as a percent)	2.11%
Expected dividend yield (as a percent)	5.33%
Expected volatility (as a percent)	24.00%
Stock Options
Outstanding, at the beginning of the period (in shares)	2,046,355
Granted (in shares)	319,234
Exercised (in shares)	(145,955)
Outstanding at the end of the period (in shares)	2,219,634
Exercisable at the end of the period (in shares)	1,463,836
Weighted-Average Exercise Price
Outstanding at the beginning of the period (in dollars per share)	$ 49.25
Granted (in dollars per share)	$ 56.00
Exercised (in dollars per share)	$ 44.03
Outstanding at the end of the period (in dollars per share)	$ 50.56
Exercisable at the end of the period (in dollars per share)	$ 49.78
Weighted-Average Remaining Contractual Life (in Years)
Outstanding at the beginning of the period	6 years 4 days
Exercisable at the end of the period	4 years 6 months 22 days
Outstanding at the end of the period	6 years 4 days
Aggregate Intrinsic Value
Outstanding at the end of the period (in dollars)	$ 16.9
Exercisable at the end of the period (in dollars)	12.4
Additional disclosures
Compensation cost not yet recognized	2.6
Period over which compensation cost is to be recognized	2 years
Intrinsic value of options exercised	$ 1.9	$ 2.0

XML

DISCONTINUED OPERATIONS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Discontinued operations
Discontinued operations, net of tax	$ 6.1	$ 0.9
Holding Company and Other
Discontinued operations
Discontinued operations, net of tax	$ 6.0	$ 1.9

XML

VARIABLE INTEREST ENTITIES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2013 MW	Mar. 31, 2013 WPS Fox Energy Company, LLC MW	Dec. 31, 2012 AMP Trillium LLC	Dec. 31, 2012 AMP Trillium LLC AMP Americas LLC	Dec. 31, 2011 PTI CNG Fuels LLC
VARIABLE INTEREST ENTITIES
Obligations to purchase energy under power purchase agreement (in megawatts)	0
Contracted capacity under a power purchase agreement (in megawatts)	17.5	500
Variable Interest Entity
Contract termination fee related to tolling arrangement	$ (50.0)	$ 50.0
Variable interest entity ownership interest acquired (as a percent)			30.00%	70.00%	50.00%
Contracted capacity under a power purchase agreement (in megawatts)	17.5	500

XML

FAIR VALUE (Tables)

3 Months Ended

Mar. 31, 2013

FAIR VALUE

Fair value of assets and liabilities measured on a recurring basis, categorized by level within the fair value hierarchy

	March 31, 2013
(Millions)	Level 1		Level 2		Level 3		Total
Assets
Risk Management Assets
Utility Segments
Natural gas contracts	$	1.2	$	10.5	$	—	$	11.7
Financial transmission rights (FTRs)	—		—		1.0		1.0
Petroleum product contracts	0.1		—		—		0.1
Coal contracts	—		—		0.1		0.1
Nonregulated Segments
Natural gas contracts	10.2		21.2		2.9		34.3
Electric contracts	64.0		107.9		13.7		185.6
Total Risk Management Assets	$	75.5	$	139.6	$	17.7	$	232.8
Investment in exchange-traded funds	$	12.4	$	—	$	—	$	12.4
Liabilities
Risk Management Liabilities
Utility Segments
Natural gas contracts	$	—	$	3.8	$	—	$	3.8
FTRs	—		—		0.1		0.1
Coal contracts	—		0.1		4.7		4.8
Nonregulated Segments
Natural gas contracts	9.0		14.8		1.2		25.0
Electric contracts	78.6		70.3		7.6		156.5
Total Risk Management Liabilities	$	87.6	$	89.0	$	13.6	$	190.2

	December 31, 2012
(Millions)	Level 1		Level 2		Level 3		Total
Assets
Risk Management Assets
Utility Segments
Natural gas contracts	$	0.3	$	3.1	$	—	$	3.4
FTRs	—		—		2.1		2.1
Petroleum product contracts	0.2		—		—		0.2
Coal contracts	—		—		2.5		2.5
Nonregulated Segments
Natural gas contracts	21.4		36.4		5.4		63.2
Electric contracts	48.4		61.3		9.6		119.3
Total Risk Management Assets	$	70.3	$	100.8	$	19.6	$	190.7
Investment in exchange-traded funds	$	11.8	$	—	$	—	$	11.8
Liabilities
Risk Management Liabilities
Utility Segments
Natural gas contracts	$	1.1	$	14.1	$	—	$	15.2
FTRs	—		—		0.1		0.1
Coal contracts	—		—		9.0		9.0
Nonregulated Segments
Natural gas contracts	17.7		36.9		1.5		56.1
Electric contracts	54.9		91.1		13.9		159.9
Total Risk Management Liabilities	$	73.7	$	142.1	$	24.5	$	240.3

Schedule of transfers between the levels of the fair value hierarchy

	Nonregulated Segments — Natural Gas Contracts
	Three Months Ended March 31, 2013						Three Months Ended March 31, 2012
(Millions)	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Transfers into Level 1 from	N/A		$	—	$	—	N/A		$	—	$	—
Transfers into Level 2 from	$	—	N/A		—		$	—	N/A		1.3
Transfers into Level 3 from	—		0.2		N/A		—		2.4		N/A

	Nonregulated Segments — Electric Contracts
	Three Months Ended March 31, 2013						Three Months Ended March 31, 2012
(Millions)	Level 1		Level 2		Level 3		Level 1		Level 2			Level 3
Transfers into Level 1 from	N/A		$	—	$	—	N/A		$	—		$	—
Transfers into Level 2 from	$	—	N/A		5.5		$	—	N/A			(0.1		)
Transfers into Level 3 from	—		—		N/A		—		(5.0		)	N/A

Significant internally-developed unobservable inputs used in the valuation of derivatives categorized in Level 3

	Fair Value (Millions)
	Assets		Liabilities		Valuation Technique	Unobservable Input	Average or Range
Utility Segments
FTRs	$	1.0	$	0.1	Market-based	Forward market prices ($/megawatt-month) (1)	203.72
Coal contracts	0.1		4.7		Market-based	Forward market prices ($/ton) (2)	11.64 — 13.90
Nonregulated Segments
Natural gas contracts	2.9		1.2		Market-based	Forward market prices ($/dekatherm) (3)	(0.08) — 1.99
						Probability of default	11.6% — 51.0%
Electric contracts	13.7		7.6		Market-based	Forward market prices ($/megawatt-hours) (3)	(9.55) — 44.03
						Option volatilities (4)	19.0% — 80.0%

⁽¹⁾  Represents forward market prices developed using historical cleared pricing data from MISO used in the valuation of FTRs.

⁽²⁾  Represents third-party forward market pricing used in the valuation of our coal contracts.

⁽³⁾  Represents unobservable basis spreads developed using historical settled prices that are applied to observable market prices at various natural gas and electric locations, as well as unobservable adjustments made to extend observable market prices beyond the quoted period through the end of the transaction term.

⁽⁴⁾  Represents the range of volatilities used in the valuation of options.

Schedule of the reconciliation of changes in Level 3 fair value measurements

Three Months Ended March 31, 2013	Nonregulated Segments						Utility Segments
(Millions)	Natural Gas			Electric			FTRs			Coal Contracts			Total
Balance at the beginning of the period	$	3.9		$	(4.3	)	$	2.0		$	(6.5	)	$	(4.9	)
Net realized and unrealized (losses) gains included in earnings	(1.5		)	15.1			0.3			—			13.9
Net unrealized (losses) gains recorded as regulatory assets or liabilities	—			—			(0.2		)	3.1			2.9
Purchases	—			0.7			—			—			0.7
Settlements	(0.9		)	0.1			(1.2		)	(1.2		)	(3.2		)
Net transfers into Level 3	0.2			—			—			—			0.2
Net transfers out of Level 3	—			(5.5		)	—			—			(5.5		)
Balance at the end of the period	$	1.7		$	6.1		$	0.9		$	(4.6	)	$	4.1
Net unrealized (losses) gains included in earnings related to instruments still held at the end of the period	$	(1.5	)	$	15.1		$	—		$	—		$	13.6

Three Months Ended March 31, 2012	Nonregulated Segments						Utility Segments
(Millions)	Natural Gas			Electric			FTRs			Coal Contract			Total
Balance at the beginning of the period	$	8.3		$	(11.5	)	$	2.2		$	(6.9	)	$	(7.9	)
Net realized and unrealized gains (losses) included in earnings	4.1			(7.7		)	0.5			—			(3.1		)
Net unrealized gains (losses) recorded as regulatory assets or liabilities	—			—			0.1			(5.8		)	(5.7		)
Purchases	—			1.1			—			—			1.1
Sales	—			—			(0.1		)	—			(0.1		)
Settlements	(2.6		)	1.1			(1.8		)	(0.7		)	(4.0		)
Net transfers into Level 3	2.4			(5.0		)	—			—			(2.6		)
Net transfers out of Level 3	(1.3		)	0.1			—			—			(1.2		)
Balance at the end of the period	$	10.9		$	(21.9	)	$	0.9		$	(13.4	)	$	(23.5	)
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	$	4.1		$	(7.7	)	$	—		$	—		$	(3.6	)

Schedule of carrying value and estimated fair value of financial instruments

	March 31, 2013				December 31, 2012
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	2,223.2	$	2,376.2	$	2,245.2	$	2,425.8
Preferred stock of subsidiary	51.1		61.7		51.1		52.7

XML

ACQUISITIONS (Tables)

3 Months Ended

Mar. 31, 2013

ACQUISITIONS

Schedule of estimated fair values of the assets acquired and the liabilities assumed

(Millions)
Assets acquired
Inventories	$	3.0
Other current assets	0.6
Property, plant, and equipment	374.4
Other long-term assets *	15.6
Total assets acquired	$	393.6
Liabilities assumed
Accounts payable	$	2.0
Total liabilities assumed	$	2.0

* Relates to intangible assets recorded for contractual services agreements. See Note 8, "Goodwill and Other Intangible Assets," for more information.

XML

FAIR VALUE (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Assets
Risk Management Assets	$ 232.8	$ 190.7
Liabilities
Risk Management Liabilities	190.2	240.3
Level 1 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	75.5	70.3
Investment in exchange-traded funds	12.4	11.8
Liabilities
Risk Management Liabilities	87.6	73.7
Level 2 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	139.6	100.8
Liabilities
Risk Management Liabilities	89.0	142.1
Level 3 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	17.7	19.6
Liabilities
Risk Management Liabilities	13.6	24.5
Total, Fair value | Fair value measurements on a recurring basis
Assets
Risk Management Assets	232.8	190.7
Investment in exchange-traded funds	12.4	11.8
Liabilities
Risk Management Liabilities	190.2	240.3
Utility Segments | Natural gas contracts | Level 1 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	1.2	0.3
Liabilities
Risk Management Liabilities		1.1
Utility Segments | Natural gas contracts | Level 2 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	10.5	3.1
Liabilities
Risk Management Liabilities	3.8	14.1
Utility Segments | Natural gas contracts | Total, Fair value | Fair value measurements on a recurring basis
Assets
Risk Management Assets	11.7	3.4
Liabilities
Risk Management Liabilities	3.8	15.2
Utility Segments | FTRs | Level 3 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	1.0	2.1
Liabilities
Risk Management Liabilities	0.1	0.1
Utility Segments | FTRs | Total, Fair value | Fair value measurements on a recurring basis
Assets
Risk Management Assets	1.0	2.1
Liabilities
Risk Management Liabilities	0.1	0.1
Utility Segments | Petroleum product contracts | Level 1 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	0.1	0.2
Utility Segments | Petroleum product contracts | Total, Fair value | Fair value measurements on a recurring basis
Assets
Risk Management Assets	0.1	0.2
Utility Segments | Coal contract | Level 2 | Fair value measurements on a recurring basis
Liabilities
Risk Management Liabilities	0.1
Utility Segments | Coal contract | Level 3 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	0.1	2.5
Liabilities
Risk Management Liabilities	4.7	9.0
Utility Segments | Coal contract | Total, Fair value | Fair value measurements on a recurring basis
Assets
Risk Management Assets	0.1	2.5
Liabilities
Risk Management Liabilities	4.8	9.0
Nonregulated Segments | Natural gas contracts | Level 1 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	10.2	21.4
Liabilities
Risk Management Liabilities	9.0	17.7
Nonregulated Segments | Natural gas contracts | Level 2 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	21.2	36.4
Liabilities
Risk Management Liabilities	14.8	36.9
Nonregulated Segments | Natural gas contracts | Level 3 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	2.9	5.4
Liabilities
Risk Management Liabilities	1.2	1.5
Nonregulated Segments | Natural gas contracts | Total, Fair value | Fair value measurements on a recurring basis
Assets
Risk Management Assets	34.3	63.2
Liabilities
Risk Management Liabilities	25.0	56.1
Nonregulated Segments | Electric contracts | Level 1 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	64.0	48.4
Liabilities
Risk Management Liabilities	78.6	54.9
Nonregulated Segments | Electric contracts | Level 2 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	107.9	61.3
Liabilities
Risk Management Liabilities	70.3	91.1
Nonregulated Segments | Electric contracts | Level 3 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	13.7	9.6
Liabilities
Risk Management Liabilities	7.6	13.9
Nonregulated Segments | Electric contracts | Total, Fair value | Fair value measurements on a recurring basis
Assets
Risk Management Assets	185.6	119.3
Liabilities
Risk Management Liabilities	$ 156.5	$ 159.9

XML

COMMON EQUITY (Details 2) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Numerator:
Net income from continuing operations	$ 182.2	$ 98.8
Discontinued operations, net of tax	6.1	0.9
Preferred stock dividends of subsidiary	(0.8)	(0.8)
Net income attributed to common shareholders	$ 187.5	$ 98.9
Denominator:
Average shares of common stock - basic	78.7	78.6
Effect of dilutive securities - Stock-based compensation (in shares)	0.4	0.4
Effect of dilutive securities - Deferred compensation (in shares)	0.2	0.2
Average shares of common stock - diluted	79.3	79.2
Earnings (Loss) per common share
Basic (in dollars per share)	$ 2.38	$ 1.26
Diluted (in dollars per share)	$ 2.37	$ 1.25
Out-of-the-money stock options
Disclosure of antidilutive shares
Antidilutive shares excluded from calculation of diluted earnings per share	0.2	0.8

XML

INVESTMENT IN ATC (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Changes in equity method investments
Equity method investments balance at beginning of period	$ 512.2
Add: Earnings from equity method investment	22.3	21.1
Add: Capital contributions	1.7	10.4
Equity method investments balance at end of period	518.3
ATC
Investments in affiliates, at equity method
Equity method investment, ownership interest (as a percent)	34.00%
Changes in equity method investments
Equity method investments balance at beginning of period	476.6	439.4
Add: Earnings from equity method investment	21.7	20.8
Add: Capital contributions	1.7	3.4
Less: Dividends received	17.3	16.7
Equity method investments balance at end of period	$ 482.7	$ 446.9

XML

ACCUMULATED OTHER COMPREHENSIVE LOSS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
ACCUMULATED OTHER COMPREHENSIVE INCOME
Accumulated other comprehensive loss, balance at beginning of period	$ (40.9)
Other comprehensive income before reclassifications	0.1
Amounts reclassified out of accumulated other comprehensive loss	1.5
Net current period other comprehensive income	1.6
Accumulated other comprehensive loss, balance at end of period	(39.3)
Cash Flow Hedges
ACCUMULATED OTHER COMPREHENSIVE INCOME
Accumulated other comprehensive loss, balance at beginning of period	(5.2)
Other comprehensive income before reclassifications	0.1
Amounts reclassified out of accumulated other comprehensive loss	0.9
Net current period other comprehensive income	1.0
Accumulated other comprehensive loss, balance at end of period	(4.2)
Defined Benefit Pension Plans
ACCUMULATED OTHER COMPREHENSIVE INCOME
Accumulated other comprehensive loss, balance at beginning of period	(35.7)
Amounts reclassified out of accumulated other comprehensive loss	0.6
Net current period other comprehensive income	0.6
Accumulated other comprehensive loss, balance at end of period	$ (35.1)

XML

SEGMENT OF BUSINESS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013 segment	Mar. 31, 2012
Segment Reporting Information
Number of reportable segments	5
External revenues	$ 1,678.2	$ 1,247.9
Depreciation and amortization expense	60.9	62.1
Earnings from equity method investments	22.3	21.1
Miscellaneous income	5.7	2.4
Interest expense	29.3	30.4
Provision (benefit) for income taxes	109.6	47.4
Net income (loss) from continuing operations	182.2	98.8
Discontinued operations, net of tax	6.1	0.9
Preferred stock dividends of subsidiary	(0.8)	(0.8)
Net income (loss) attributed to common shareholders	187.5	98.9
ATC
Segment Reporting Information
Equity method investment, ownership interest (as a percent)	34.00%
Earnings from equity method investments	21.7	20.8
Holding Company and Other
Segment Reporting Information
Discontinued operations, net of tax	6.0	1.9
Reconciling Eliminations
Segment Reporting Information
Intersegment revenues	(2.6)	(2.6)
Depreciation and amortization expense	(0.1)	(0.1)
Miscellaneous income	(3.7)	(4.2)
Interest expense	(3.7)	(4.2)
Regulated Operations
Segment Reporting Information
External revenues	1,123.8	971.0
Intersegment revenues	1.9	1.7
Depreciation and amortization expense	53.7	54.4
Earnings from equity method investments	21.7	20.8
Miscellaneous income	1.8	0.3
Interest expense	21.8	21.2
Provision (benefit) for income taxes	87.7	69.2
Net income (loss) from continuing operations	132.5	117.0
Preferred stock dividends of subsidiary	(0.8)	(0.8)
Net income (loss) attributed to common shareholders	131.7	116.2
Regulated Operations | Natural Gas Utility
Segment Reporting Information
External revenues	792.0	664.0
Intersegment revenues	1.9	1.7
Depreciation and amortization expense	32.2	32.4
Miscellaneous income	0.2	0.2
Interest expense	12.7	12.0
Provision (benefit) for income taxes	63.3	51.5
Net income (loss) from continuing operations	89.8	78.7
Preferred stock dividends of subsidiary	(0.1)	(0.1)
Net income (loss) attributed to common shareholders	89.7	78.6
Regulated Operations | Electric Utility
Segment Reporting Information
External revenues	331.8	307.0
Depreciation and amortization expense	21.5	22.0
Miscellaneous income	1.6	0.1
Interest expense	9.1	9.2
Provision (benefit) for income taxes	16.1	10.2
Net income (loss) from continuing operations	29.3	25.0
Preferred stock dividends of subsidiary	(0.7)	(0.7)
Net income (loss) attributed to common shareholders	28.6	24.3
Regulated Operations | Electric Transmission Investment
Segment Reporting Information
Earnings from equity method investments	21.7	20.8
Provision (benefit) for income taxes	8.3	7.5
Net income (loss) from continuing operations	13.4	13.3
Net income (loss) attributed to common shareholders	13.4	13.3
Nonutility and Nonregulated Operations | Integrys Energy Services
Segment Reporting Information
External revenues	545.4	269.4
Intersegment revenues	0.3	0.2
Depreciation and amortization expense	2.7	2.3
Earnings from equity method investments	0.2	0.1
Miscellaneous income	0.4	0.6
Interest expense	0.5	0.5
Provision (benefit) for income taxes	27.3	(12.3)
Net income (loss) from continuing operations	51.3	(19.1)
Discontinued operations, net of tax	0.1	(1.0)
Net income (loss) attributed to common shareholders	51.4	(20.1)
Nonutility and Nonregulated Operations | Holding Company and Other
Segment Reporting Information
External revenues	9.0	7.5
Intersegment revenues	0.4	0.7
Depreciation and amortization expense	4.6	5.5
Earnings from equity method investments	0.4	0.2
Miscellaneous income	7.2	5.7
Interest expense	10.7	12.9
Provision (benefit) for income taxes	(5.4)	(9.5)
Net income (loss) from continuing operations	(1.6)	0.9
Discontinued operations, net of tax	6.0	1.9
Net income (loss) attributed to common shareholders	$ 4.4	$ 2.8

XML

FAIR VALUE (Details 3) (Valuation Technique: Market-based, Level 3, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
FTRs
Significant internally-developed unobservable inputs
Fair Value, Assets	$ 1.0
Fair Value, Liabilities	0.1
FTRs | Average
Significant internally-developed unobservable inputs
Forward market prices	203.72
Coal contract
Significant internally-developed unobservable inputs
Fair Value, Assets	0.1
Fair Value, Liabilities	4.7
Coal contract | Minimum
Significant internally-developed unobservable inputs
Forward market prices	11.64
Coal contract | Maximum
Significant internally-developed unobservable inputs
Forward market prices	13.90
Natural gas contracts
Significant internally-developed unobservable inputs
Fair Value, Assets	2.9
Fair Value, Liabilities	1.2
Natural gas contracts | Minimum
Significant internally-developed unobservable inputs
Forward market prices	(0.08)
Probability of default (as a percent)	11.60%
Natural gas contracts | Maximum
Significant internally-developed unobservable inputs
Forward market prices	1.99
Probability of default (as a percent)	51.00%
Electric contracts
Significant internally-developed unobservable inputs
Fair Value, Assets	13.7
Fair Value, Liabilities	$ 7.6
Electric contracts | Minimum
Significant internally-developed unobservable inputs
Forward market prices	(9.55)
Option volatilities (as a percent)	19.00%
Electric contracts | Maximum
Significant internally-developed unobservable inputs
Forward market prices	44.03
Option volatilities (as a percent)	80.00%

XML

ACCUMULATED OTHER COMPREHENSIVE LOSS (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Amount reclassified out of AOCI
Operating and maintenance expense	$ (295.1)	$ (259.3)
Nonregulated revenues	554.4	276.9
Interest expense	(29.3)	(30.4)
Income before taxes	291.8	146.2
Tax expense	(109.6)	(47.4)
Net income attributed to common shareholders	187.5	98.9
Total reclassifications	(1.5)
Amount Reclassified
Amount reclassified out of AOCI
Total reclassifications	(1.5)
Losses on cash flow hedges
Amount reclassified out of AOCI
Total reclassifications	(0.9)
Losses on cash flow hedges | Amount Reclassified
Amount reclassified out of AOCI
Income before taxes	1.5
Tax expense	0.6
Net income attributed to common shareholders	0.9
Losses on cash flow hedges | Amount Reclassified | Utility commodity derivative contracts
Amount reclassified out of AOCI
Operating and maintenance expense	0.2
Losses on cash flow hedges | Amount Reclassified | Non-regulated commodity derivative contracts
Amount reclassified out of AOCI
Nonregulated revenues	1.1
Losses on cash flow hedges | Amount Reclassified | Interest rate hedges
Amount reclassified out of AOCI
Interest expense	0.2
Defined benefit pension plans
Amount reclassified out of AOCI
Total reclassifications	(0.6)
Defined benefit pension plans | Amount Reclassified
Amount reclassified out of AOCI
Amortization of prior service costs	(0.1)
Amortization of actuarial losses	1.1
Income before taxes	1.0
Tax expense	0.4
Net income attributed to common shareholders	$ 0.6

XML

STOCK-BASED COMPENSATION (Details 3) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Performance Stock Rights
Weighted-average fair values per stock option along with the assumptions incorporated into the valuation models
Risk-free interest rate, minimum (as a percent)	0.17%
Risk-free interest rate, maximum (as a percent)	1.27%
Expected volatility, minimum (as a percent)	19.00%
Expected volatility, maximum (as a percent)	36.00%
Weighted-Average Grant Date Fair Value
Granted (in dollars per share)	$ 48.50	$ 52.70
Additional disclosures
Compensation cost not yet recognized	$ 5.9
Period over which compensation cost is to be recognized	1 year 6 months
Tax benefit realized from the distribution of shares	3.6	1.9
Total intrinsic value
Total intrinsic value of performance shares distributed during the period	8.8	4.7
Performance Stock Rights | Minimum
Weighted-average fair values per stock option along with the assumptions incorporated into the valuation models
Expected dividend yield (as a percent)	5.18%
Period of historical volatility used to estimate expected volatility	2 years
Performance Stock Rights | Maximum
Weighted-average fair values per stock option along with the assumptions incorporated into the valuation models
Expected dividend yield (as a percent)	5.34%
Period of historical volatility used to estimate expected volatility	3 years
Performance Stock Rights accounted for as Equity awards
Performance Stock Rights and Restricted Shares Units Activity
Outstanding at the beginning of the period (in shares)	108,314
Granted (in shares)	22,636
Distributed (in shares)	(94,758)
Adjustment for final payout (in shares)	21,867
Outstanding at the end of period (in shares)	58,059
Weighted-Average Grant Date Fair Value
Outstanding at the beginning of the period (in dollars per share)	$ 65.38
Granted (in dollars per share)	$ 48.50
Distributed (in dollars per share)	$ 72.36
Adjustment for final payout (in dollars per shares)	$ 72.36
Outstanding at the end of the period (in dollars per share)	$ 50.04
Performance Stock Rights accounted as Liability awards
Performance Stock Rights and Restricted Shares Units Activity
Outstanding at the beginning of the period (in shares)	189,093
Granted (in shares)	90,496
Distributed (in shares)	(61,753)
Adjustment for final payout (in shares)	14,255
Outstanding at the end of period (in shares)	232,091
Weighted-Average Grant Date Fair Value
Outstanding at the end of the period (in dollars per share)	$ 48.06
Restricted Share Unit Awards
Performance Stock Rights and Restricted Shares Units Activity
Outstanding at the beginning of the period (in shares)	505,690
Granted (in shares)	189,094
Dividend equivalents (in shares)	5,818
Vested and released (in shares)	(204,072)
Forfeited (in shares)	(1,507)
Outstanding at the end of period (in shares)	495,023
Weighted-Average Grant Date Fair Value
Outstanding at the beginning of the period (in dollars per share)	$ 48.38
Granted (in dollars per share)	$ 56.00	$ 53.24
Dividend equivalents (in dollars per share)	$ 52.20
Vested and released (in dollars per share)	$ 46.28
Forfeited (in dollars per share)	$ 48.47
Outstanding at the end of the period (in dollars per share)	$ 52.20
Additional disclosures
Compensation cost not yet recognized	17.4
Period over which compensation cost is to be recognized	2 years 6 months
Tax benefit realized from the distribution of shares	4.6	4.2
Total intrinsic value
Total intrinsic value of awards vested and released	$ 11.4	$ 10.4
Nonemployee director deferred stock units
Additional disclosures
Vesting period	1 year

XML

VARIABLE INTEREST ENTITIES

3 Months Ended

Mar. 31, 2013

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

NOTE 18 — VARIABLE INTEREST ENTITIES

In 2012, ITF formed AMP Trillium LLC as a joint venture with AMP Americas LLC. ITF owns 30% and AMP Americas LLC owns 70% of the joint venture. The joint venture was established to own and operate compressed natural gas fueling stations. The preferred source of capital funding for the joint venture is loans from ITF. We determined that the joint venture is a variable interest entity and that ITF is the primary beneficiary, which requires us to consolidate the assets, liabilities, and statements of income of the joint venture. At March 31, 2013, and December 31, 2012, our variable interests in the joint venture included an insignificant equity investment and insignificant receivables. Our maximum exposure to loss as a result of this joint venture was not significant. The carrying amounts of AMP Trillium LLC assets and liabilities included on our balance sheets were also not significant.

In 2011, ITF formed Integrys PTI CNG Fuels LLC as a joint venture with Paper Transport Inc. ITF and Paper Transport Inc. each own 50% of the joint venture. The joint venture was established to own and operate compressed natural gas fueling stations. The preferred source of capital funding for the joint venture is loans from ITF. We determined that the joint venture is a variable interest entity and that ITF is the primary beneficiary, which requires us to consolidate the assets, liabilities, and statements of income of the joint venture. At March 31, 2013, and December 31, 2012, our variable interests in the joint venture included an insignificant equity investment and insignificant receivables. Our maximum exposure to loss as a result of this joint venture was not significant. The carrying amounts of Integrys PTI CNG Fuels LLC assets and liabilities included on our balance sheets were also not significant.

We have a variable interest in an entity through a power purchase agreement at UPPCO that reimburses an independent power producing entity for coal costs relating to purchased energy. There is no obligation to purchase energy under this agreement. This contract for 17.5 megawatts of capacity expires in 2014. We evaluated this variable interest entity for possible consolidation. We considered which interest holder has the power to direct the activities that most significantly impact the economics of the variable interest entity; this interest holder is considered the primary beneficiary of the entity and is required to consolidate the entity. For a variety of reasons, including qualitative factors such as the length of the remaining term of the contract compared with the remaining life of the plant and the fact that we do not have the power to direct the operations and maintenance of the facility, we determined we are not the primary beneficiary of the variable interest entity. At March 31, 2013, and December 31, 2012, the assets and liabilities on the balance sheets that related to our involvement with this variable interest entity pertained to working capital accounts and represented the amounts we owed for current deliveries of power. We have not guaranteed any debt or provided any equity support, liquidity arrangements, performance guarantees, or other commitments associated with the contract. There is not a significant potential exposure to loss as a result of involvement with the variable interest entity.

We also had a variable interest in Fox Energy Company LLC through a power purchase agreement at WPS that contained a tolling arrangement related to the cost of fuel. In connection with the purchase of Fox Energy Company LLC, WPS paid $50.0 million for the early termination of this 500 megawatt agreement. See Note 4, “Acquisitions,” for more information regarding this purchase. We evaluated this variable interest entity for possible consolidation and determined that consolidation was not required since we were not the primary beneficiary of the variable interest entity. The assets and liabilities on our December 31, 2012 balance sheet that related to our involvement with this variable interest entity pertained to working capital accounts and represented the amounts we owed for current deliveries of power.

XML

RISK MANAGEMENT ACTIVITIES (Details 2) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Assets
Gross Amount	$ 232.5	$ 188.2
Derivative assets not subject to master netting or similar arrangements	0.3	2.5
Total risk management assets, Gross Amount	232.8	190.7
Gross Amount Not Offset in the Balance Sheet, including Cash Collateral	163.7	148.4
Net Amount	68.8	39.8
Total risk management assets, Net Amount	69.1	42.3
Liabilities
Gross Amount	185.3	230.7
Derivative liabilities not subject to master netting or similar arrangements	4.9	9.6
Total risk management liabilities, Gross Amount	190.2	240.3
Gross Amount Not Offset in the Balance Sheet, including Cash Collateral	163.7	163.6
Net Amount	21.6	67.1
Total risk management liabilities, Net Amount	26.5	76.7
Utility Segments
Assets
Gross Amount	12.8	5.7
Gross Amount Not Offset in the Balance Sheet, including Cash Collateral	3.4	3.0
Net Amount	9.4	2.7
Liabilities
Gross Amount	3.9	15.3
Gross Amount Not Offset in the Balance Sheet, including Cash Collateral	3.4	3.8
Net Amount	0.5	11.5
Nonregulated Segments
Assets
Gross Amount	219.7	182.5
Gross Amount Not Offset in the Balance Sheet, including Cash Collateral	160.3	145.4
Net Amount	59.4	37.1
Liabilities
Gross Amount	181.4	215.4
Gross Amount Not Offset in the Balance Sheet, including Cash Collateral	160.3	159.8
Net Amount	$ 21.1	$ 55.6

XML

EMPLOYEE BENEFITS PLANS (Tables)

3 Months Ended

Mar. 31, 2013

EMPLOYEE BENEFITS PLANS

Schedule of components of net periodic benefit cost for benefit plans

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended, March 31,						Three Months Ended, March 31,
(Millions)	2013			2012			2013			2012
Service cost	$	7.5		$	12.4		$	6.5		$	5.5
Interest cost	17.8			19.8			6.3			7.2
Expected return on plan assets	(26.6		)	(27.1		)	(7.7		)	(7.0		)
Amortization of transition obligation	—			—			—			0.1
Amortization of prior service cost (credit)	1.0			1.2			(0.6		)	(0.9		)
Amortization of net actuarial loss	13.5			8.3			2.0			1.6
Net periodic benefit cost	$	13.2		$	14.6		$	6.5		$	6.5

XML

COMMON EQUITY (Details 4) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Capital Transactions with Subsidiaries
Dividends To Parent	$ 44.4
Return Of Capital To Parent	21.0
Equity Contributions From Parent	213.4
WPS
Capital Transactions with Subsidiaries
Dividends To Parent	27.1
Equity Contributions From Parent	200.0
WPS | WPS Investments, LLC
Capital Transactions with Subsidiaries
Ownership interest (as a percent)	11.66%
WPS Investments, LLC
Capital Transactions with Subsidiaries
Dividends To Parent	17.3
Equity Contributions From Parent	1.7
Ownership interest (as a percent)	85.86%
MERC
Capital Transactions with Subsidiaries
Return Of Capital To Parent	21.0
UPPCO | WPS Investments, LLC
Capital Transactions with Subsidiaries
Ownership interest (as a percent)	2.48%
ITF
Capital Transactions with Subsidiaries
Equity Contributions From Parent	$ 11.7

XML

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)

3 Months Ended

Mar. 31, 2013

SHORT-TERM DEBT AND LINES OF CREDIT

Schedule of short-term borrowings

(Millions, except percentages)	March 31, 2013		December 31, 2012
Commercial paper	$	556.4	$	482.4
Average discount rate on commercial paper	0.33%		0.40%
Loan under term credit facility *	$	200.0	—
Average interest rate on loan under term credit facility	0.80%		—

* Relates to the purchase of Fox Energy Company LLC. See Note 4, "Acquisitions," for more information regarding this purchase.

Schedule of average amount of short-term borrowings

(Millions)	2013		2012
Average amount of commercial paper	$	400.7	$	357.5
Average amount of loan under term credit facility	8.9		—

Schedule of revolving credit facilities and remaining available capacity

(Millions)	Maturity	March 31, 2013		December 31, 2012
Revolving credit facility (Integrys Energy Group)	05/17/2014	$	275.0	$	275.0
Revolving credit facility (Integrys Energy Group)	05/17/2016	200.0		200.0
Revolving credit facility (Integrys Energy Group)	06/13/2017	635.0		635.0
Revolving credit facility (WPS)	05/17/2014	135.0		135.0
Revolving credit facility (WPS)	06/13/2017	115.0		115.0
Revolving credit facility (PGL)	06/13/2017	250.0		250.0
Term credit facility (WPS) *	12/31/2013	200.0		—
Total short-term credit capacity		$	1,810.0	$	1,610.0
Less:
Letters of credit issued inside credit facilities		$	29.1	$	25.5
Loan outstanding under term credit facility *		200.0		—
Commercial paper outstanding		556.4		482.4
Accrued interest or original discount on outstanding commercial paper		0.1		—
Available capacity under existing agreements		$	1,024.4	$	1,102.1

* Relates to the purchase of Fox Energy Company LLC. See Note 4, "Acquisitions," for more information regarding this purchase.

XML

RISK MANAGEMENT ACTIVITIES (Details 4) (Utility Segments, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013 Natural gas contracts Balance Sheet - Regulatory assets (current)	Mar. 31, 2012 Natural gas contracts Balance Sheet - Regulatory assets (current)	Mar. 31, 2013 Natural gas contracts Balance Sheet - Regulatory assets (long-term)	Mar. 31, 2012 Natural gas contracts Balance Sheet - Regulatory assets (long-term)	Mar. 31, 2013 Natural gas contracts Balance Sheet - Regulatory liabilities (current)	Mar. 31, 2012 Natural gas contracts Balance Sheet - Regulatory liabilities (current)	Mar. 31, 2013 Natural gas contracts Balance Sheet - Regulatory liabilities (long-term)	Mar. 31, 2012 Natural gas contracts Balance Sheet - Regulatory liabilities (long-term)	Mar. 31, 2012 Natural gas contracts Income Statement - Utility cost of fuel, natural gas and purchased power	Mar. 31, 2013 Natural gas contracts Income Statement - Operating and maintenance expense	Mar. 31, 2013 FTRs Balance Sheet - Regulatory assets (current)	Mar. 31, 2012 FTRs Balance Sheet - Regulatory assets (current)	Mar. 31, 2013 FTRs Balance Sheet - Regulatory liabilities (current)	Mar. 31, 2012 FTRs Balance Sheet - Regulatory liabilities (current)	Mar. 31, 2012 Petroleum product contracts Balance Sheet - Regulatory assets (current)	Mar. 31, 2012 Petroleum product contracts Balance Sheet - Regulatory liabilities (current)	Mar. 31, 2012 Petroleum product contracts Income Statement - Operating and maintenance expense	Mar. 31, 2013 Coal contract Balance Sheet - Regulatory assets (current)	Mar. 31, 2012 Coal contract Balance Sheet - Regulatory assets (current)	Mar. 31, 2013 Coal contract Balance Sheet - Regulatory assets (long-term)	Mar. 31, 2012 Coal contract Balance Sheet - Regulatory assets (long-term)	Mar. 31, 2013 Coal contract Balance Sheet - Regulatory liabilities (current)	Mar. 31, 2013 Coal contract Balance Sheet - Regulatory liabilities (long-term)	Mar. 31, 2013 Purchases Natural gas contracts therm	Dec. 31, 2012 Purchases Natural gas contracts therm	Mar. 31, 2013 Purchases Petroleum product contracts bbl	Dec. 31, 2012 Purchases Petroleum product contracts bbl	Mar. 31, 2013 Purchases Coal contract T	Dec. 31, 2012 Purchases Coal contract T	Dec. 31, 2012 Sales Natural gas contracts therm	Mar. 31, 2013 Sales Coal contract T	Mar. 31, 2013 Other transactions FTRs kWh	Dec. 31, 2012 Other transactions FTRs kWh
Risk management activities
Notional volume of outstanding non-hedge derivative contracts																								595,400,000	1,072,600,000					100,000
Notional volume of outstanding non-hedge derivative contracts																																1,579,000,000	4,057,200,000
Notional volume of outstanding non-hedge derivative contracts																										50,855.0	62,811.0
Notional volume of outstanding non-hedge derivative contracts																												4,700,000	5,100,000		200,000
Unrealized gains (losses) recorded related to non-hedge derivatives	$ 13.0	$ (6.4)	$ 0.8	$ (0.8)	$ 5.9	$ (3.7)	$ 0.8	$ 0.1	$ 0.1	$ 0.2	$ 0.2	$ 0.4	$ (0.4)	$ (0.3)	$ 0.1	$ 0.1	$ 0.1	$ 1.9	$ (3.1)	$ 2.3	$ (3.5)	$ (0.2)	$ (2.2)

XML

GUARANTEES (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013
Guarantees
Total guarantees	$ 668.0
Expiration Less Than 1 Year	417.3
Expiration from 1 to 3 Years	31.4
Expiration Over 3 Years	219.3
Integrys Energy Services | Parental guarantees
Guarantees
Total guarantees	487.0
Guarantee exposure related to open transactions	229.7
Guarantees supporting commodity transactions
Guarantees
Total guarantees	597.1
Expiration Less Than 1 Year	368.8
Expiration from 1 to 3 Years	31.3
Expiration Over 3 Years	197.0
Guarantees supporting commodity transactions | Integrys Energy Services | Parental guarantees
Guarantees
Total guarantees	436.3
Guarantees supporting commodity transactions | MERC
Guarantees
Total guarantees	108.5
Guarantees supporting commodity transactions | MGU
Guarantees
Total guarantees	45.3
Guarantees supporting commodity transactions | IBS
Guarantees
Total guarantees	5.0
Guarantees supporting commodity transactions | UPPCO
Guarantees
Total guarantees	2.0
Standby letters of credit
Guarantees
Total guarantees	34.2
Expiration Less Than 1 Year	34.1
Expiration from 1 to 3 Years	0.1
Standby letters of credit | Integrys Energy Services | Parental guarantees
Guarantees
Total guarantees	32.5
Standby letters of credit | UPPCO, WPS, MGU, NSG, MERC, PGL, and Pinnacle CNG Systems
Guarantees
Total guarantees	1.7
Surety bonds
Guarantees
Total guarantees	14.4
Expiration Less Than 1 Year	14.4
Other guarantees
Guarantees
Total guarantees	22.3
Expiration Over 3 Years	22.3
Other guarantees | Integrys Energy Services | Texas Retail Marketing Business
Guarantees
Total guarantees	10.0
Environmental indemnification | Integrys Energy Services | Sale of Stoneman generation facility
Guarantees
Total guarantees	5.0
Indemnification and workers' compensation coverage
Guarantees
Total guarantees	$ 7.3

XML

SHORT-TERM DEBT AND LINES OF CREDIT (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
Short-term borrowings
Short-term borrowings	$ 756.4	$ 482.4
Commercial paper
Short-term borrowings
Short-term borrowings	556.4	482.4
Average discount rate (as a percent)	0.33%	0.40%
Average amount of short-term borrowings	400.7	357.5
Loan under term credit facility
Short-term borrowings
Short-term borrowings	200.0
Average interest rate (as a percent)	0.80%
Average amount of short-term borrowings	$ 8.9

XML

SEGMENT OF BUSINESS (Tables)

3 Months Ended

Mar. 31, 2013

SEGMENT OF BUSINESS

Schedule of segment revenues and net income (loss) attributed to common shareholders

	Regulated Operations											Nonutility and Nonregulated Operations
(Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			Integrys Energy Services		Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Three Months Ended
March 31, 2013
External revenues	$	792.0		$	331.8		$	—	$	1,123.8		$	545.4	$	9.0		$	—		$	1,678.2
Intersegment revenues	1.9			—			—		1.9			0.3		0.4			(2.6		)	—
Depreciation and amortization expense	32.2			21.5			—		53.7			2.7		4.6			(0.1		)	60.9
Earnings from equity method investments	—			—			21.7		21.7			0.2		0.4			—			22.3
Miscellaneous income	0.2			1.6			—		1.8			0.4		7.2			(3.7		)	5.7
Interest expense	12.7			9.1			—		21.8			0.5		10.7			(3.7		)	29.3
Provision (benefit) for income taxes	63.3			16.1			8.3		87.7			27.3		(5.4		)	—			109.6
Net income (loss) from continuing operations	89.8			29.3			13.4		132.5			51.3		(1.6		)	—			182.2
Discontinued operations	—			—			—		—			0.1		6.0			—			6.1
Preferred stock dividends of subsidiary	(0.1		)	(0.7		)	—		(0.8		)	—		—			—			(0.8		)
Net income attributed to common shareholders	89.7			28.6			13.4		131.7			51.4		4.4			—			187.5

	Regulated Operations											Nonutility and Nonregulated Operations
(Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			Integrys Energy Services			Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Three Months Ended
March 31, 2012
External revenues	$	664.0		$	307.0		$	—	$	971.0		$	269.4		$	7.5		$	—		$	1,247.9
Intersegment revenues	1.7			—			—		1.7			0.2			0.7			(2.6		)	—
Depreciation and amortization expense	32.4			22.0			—		54.4			2.3			5.5			(0.1		)	62.1
Earnings from equity method investments	—			—			20.8		20.8			0.1			0.2			—			21.1
Miscellaneous income	0.2			0.1			—		0.3			0.6			5.7			(4.2		)	2.4
Interest expense	12.0			9.2			—		21.2			0.5			12.9			(4.2		)	30.4
Provision (benefit) for income taxes	51.5			10.2			7.5		69.2			(12.3		)	(9.5		)	—			47.4
Net income (loss) from continuing operations	78.7			25.0			13.3		117.0			(19.1		)	0.9			—			98.8
Discontinued operations	—			—			—		—			(1.0		)	1.9			—			0.9
Preferred stock dividends of subsidiary	(0.1		)	(0.7		)	—		(0.8		)	—			—			—			(0.8		)
Net income (loss) attributed to common shareholders	78.6			24.3			13.3		116.2			(20.1		)	2.8			—			98.9

XML

CASH AND CASH EQUIVALENTS

3 Months Ended

Mar. 31, 2013

CASH AND CASH EQUIVALENTS

CASH AND CASH EQUIVALENTS

NOTE 2 — CASH AND CASH EQUIVALENTS

Short-term investments with an original maturity of three months or less are reported as cash equivalents.

The following is a supplemental disclosure to our statements of cash flows:

	Three Months Ended March 31
(Millions)	2013			2012
Cash paid for interest	$	4.8		$	8.9
Cash received for income taxes	(1.0		)	(33.2		)

Cash received for income taxes decreased $32.2 million primarily due to refunds received in 2012 related to prior year amended tax returns.

Significant noncash transactions were:

	Three Months Ended March 31
(Millions)	2013		2012
Construction costs funded through accounts payable	$	59.8	$	50.2
Equity issued for stock-based compensation plans	18.7		—
Equity issued for reinvested dividends	3.0		—
Risk management asset related to sale of Beaver Falls and Syracuse *	6.8		—

* See Note 5, "Discontinued Operations," for more information.

XML

SHORT-TERM DEBT AND LINES OF CREDIT (Details 2) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Short-term borrowings
Total short-term credit capacity	$ 1,810.0	$ 1,610.0
Letters of credit issued inside credit facilities	29.1	25.5
Short-term borrowings	756.4	482.4
Available capacity under existing agreements	1,024.4	1,102.1
Revolving credit facility maturing on May 17, 2014 | INTEGRYS ENERGY GROUP, INC.
Short-term borrowings
Total short-term credit capacity	275.0	275.0
Revolving credit facility maturing on May 17, 2014 | WPS
Short-term borrowings
Total short-term credit capacity	135.0	135.0
Revolving credit facility maturing on May 17, 2016 | INTEGRYS ENERGY GROUP, INC.
Short-term borrowings
Total short-term credit capacity	200.0	200.0
Revolving credit facility maturing on June 13, 2017 | INTEGRYS ENERGY GROUP, INC.
Short-term borrowings
Total short-term credit capacity	635.0	635.0
Revolving credit facility maturing on June 13, 2017 | WPS
Short-term borrowings
Total short-term credit capacity	115.0	115.0
Revolving credit facility maturing on June 13, 2017 | PGL
Short-term borrowings
Total short-term credit capacity	250.0	250.0
Term credit facility maturing on December 31, 2013
Short-term borrowings
Short-term borrowings	200.0
Term credit facility maturing on December 31, 2013 | WPS
Short-term borrowings
Total short-term credit capacity	200.0
Short-term borrowings	200.0
Commercial paper
Short-term borrowings
Short-term borrowings	556.4	482.4
Accrued interest or original discount on outstanding debt	$ 0.1

XML

STOCK-BASED COMPENSATION (Tables)

3 Months Ended

Mar. 31, 2013

STOCK-BASED COMPENSATION

Schedule of stock-based compensation expense and the related deferred tax benefit recognized in income

(Millions)	2013		2012
Stock options	$	0.4	$	0.4
Performance stock rights	2.2		1.2
Restricted share units	2.8		2.1
Nonemployee director deferred stock units	0.3		1.0
Total stock-based compensation expense	$	5.7	$	4.7
Deferred income tax benefit	$	2.3	$	1.9

Schedule of weighted-average fair values per stock option granted during the period along with the assumptions incorporated into the valuation models

	February 2013 Grant
Weighted-average fair value per option	$6.03
Expected term	5 years
Risk-free interest rate	0.18% – 2.11%
Expected dividend yield	5.33%
Expected volatility	24%

Summary of stock option activity and information related to outstanding and exercisable stock options

	Stock Options		Weighted-Average Exercise Price Per Share		Weighted-Average Remaining  Contractual Life (in Years)	Aggregate Intrinsic Value (Millions)
Outstanding at December 31, 2012	2,046,355		$	49.25
Granted	319,234		56.00
Exercised	(145,955	)	44.03
Outstanding at March 31, 2013	2,219,634		$	50.56	6.01	$	16.9
Exercisable at March 31, 2013	1,463,836		$	49.78	4.56	$	12.4

Disclosure of performance stock rights assumptions

	2013
Risk-free interest rate	0.17% – 1.27%
Expected dividend yield	5.18% – 5.34%
Expected volatility	19% – 36%

Summary of the activity related to restricted share and restricted share unit awards (equity and liability awards)

	Restricted Share Unit Awards		Weighted-AverageGrant Date Fair Value
Outstanding at December 31, 2012	505,690		$	48.38
Granted	189,094		56.00
Dividend equivalents	5,818		52.20
Vested and released	(204,072	)	46.28
Forfeited	(1,507	)	48.47
Outstanding at March 31, 2013	495,023		$	52.20

Performance Stock Rights accounted for as Equity awards

Information related to Share based awards

Summary of the activity related to performance stock rights

	Performance Stock Rights		Weighted-Average Fair Value *
Outstanding at December 31, 2012	108,314		$	65.38
Granted	22,636		48.50
Distributed	(94,758	)	72.36
Adjustment for final payout	21,867		72.36
Outstanding at March 31, 2013	58,059		$	50.04

* Reflects the weighted-average fair value used to measure equity awards. Equity awards are measured using the grant date fair value or the fair value on the modification date.

Performance Stock Rights accounted as Liability awards

Information related to Share based awards

Summary of the activity related to performance stock rights

	Performance Stock Rights
Outstanding at December 31, 2012	189,093
Granted	90,496
Distributed	(61,753	)
Adjustment for final payout	14,255
Outstanding at March 31, 2013	232,091

XML

SEGMENT OF BUSINESS

3 Months Ended

Mar. 31, 2013

SEGMENT OF BUSINESS

SEGMENT OF BUSINESS

NOTE 22 — SEGMENT OF BUSINESS

At March 31, 2013, we reported five segments, which are described below.

• The natural gas utility segment includes the regulated natural gas utility operations of MERC, MGU, NSG, PGL, and WPS.

• The electric utility segment includes the regulated electric utility operations of UPPCO and WPS.

• The electric transmission investment segment includes our approximate 34% ownership interest in ATC. ATC is a federally regulated electric transmission company.

• Integrys Energy Services is a diversified nonregulated retail energy supply and services company that primarily sells electricity and natural gas in deregulated markets. In addition, Integrys Energy Services invests in energy assets with renewable attributes.

• The holding company and other segment includes the operations of the Integrys Energy Group holding company, ITF, and the PELLC holding company, along with any nonutility activities at IBS, MERC, MGU, NSG, PGL, UPPCO, and WPS.

The tables below present information related to our reportable segments:

	Regulated Operations											Nonutility and Nonregulated Operations
(Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			Integrys Energy Services		Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Three Months Ended
March 31, 2013
External revenues	$	792.0		$	331.8		$	—	$	1,123.8		$	545.4	$	9.0		$	—		$	1,678.2
Intersegment revenues	1.9			—			—		1.9			0.3		0.4			(2.6		)	—
Depreciation and amortization expense	32.2			21.5			—		53.7			2.7		4.6			(0.1		)	60.9
Earnings from equity method investments	—			—			21.7		21.7			0.2		0.4			—			22.3
Miscellaneous income	0.2			1.6			—		1.8			0.4		7.2			(3.7		)	5.7
Interest expense	12.7			9.1			—		21.8			0.5		10.7			(3.7		)	29.3
Provision (benefit) for income taxes	63.3			16.1			8.3		87.7			27.3		(5.4		)	—			109.6
Net income (loss) from continuing operations	89.8			29.3			13.4		132.5			51.3		(1.6		)	—			182.2
Discontinued operations	—			—			—		—			0.1		6.0			—			6.1
Preferred stock dividends of subsidiary	(0.1		)	(0.7		)	—		(0.8		)	—		—			—			(0.8		)
Net income attributed to common shareholders	89.7			28.6			13.4		131.7			51.4		4.4			—			187.5

	Regulated Operations											Nonutility and Nonregulated Operations
(Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			Integrys Energy Services			Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Three Months Ended
March 31, 2012
External revenues	$	664.0		$	307.0		$	—	$	971.0		$	269.4		$	7.5		$	—		$	1,247.9
Intersegment revenues	1.7			—			—		1.7			0.2			0.7			(2.6		)	—
Depreciation and amortization expense	32.4			22.0			—		54.4			2.3			5.5			(0.1		)	62.1
Earnings from equity method investments	—			—			20.8		20.8			0.1			0.2			—			21.1
Miscellaneous income	0.2			0.1			—		0.3			0.6			5.7			(4.2		)	2.4
Interest expense	12.0			9.2			—		21.2			0.5			12.9			(4.2		)	30.4
Provision (benefit) for income taxes	51.5			10.2			7.5		69.2			(12.3		)	(9.5		)	—			47.4
Net income (loss) from continuing operations	78.7			25.0			13.3		117.0			(19.1		)	0.9			—			98.8
Discontinued operations	—			—			—		—			(1.0		)	1.9			—			0.9
Preferred stock dividends of subsidiary	(0.1		)	(0.7		)	—		(0.8		)	—			—			—			(0.8		)
Net income (loss) attributed to common shareholders	78.6			24.3			13.3		116.2			(20.1		)	2.8			—			98.9

XML

REGULATORY ENVIRONMENT

3 Months Ended

Mar. 31, 2013

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT

NOTE 21 — REGULATORY ENVIRONMENT

Wisconsin

2014 Rates

On March 29, 2013, WPS filed an application with the PSCW to increase retail electric and natural gas rates $71.1 million and $19.0 million, respectively, with rates proposed to be effective January 1, 2014. The filing includes a request for a 10.75% return on common equity and a common equity ratio of 51.11% in WPS's regulatory capital structure. The proposed retail electric rate increase is primarily driven by the purchase and operation of the Fox Energy Center, the completion of a one-time fuel refund to customers in 2013, increased electric transmission costs, and additional construction related to the installation of environmental controls and the improvement of electric reliability. Partially offsetting these increases are lower purchased power capacity costs and a refund to customers resulting from WPS's decoupling mechanism. The proposed retail natural gas rate increase is generally the result of the recovery of amounts related to decoupling, increased costs of inspecting natural gas lines for safety, and general inflation.

2013 Rates

On December 6, 2012, the PSCW issued an order approving a settlement agreement for WPS, effective January 1, 2013. The settlement agreement includes a $28.5 million imputed retail electric rate increase, partially offset by the actual 2012 fuel refund of $20.5 million. The difference between the 2012 fuel refund and the rate increase is being deferred for recovery in a future rate proceeding. As a result, there is no change to customers' 2013 retail electric rates. The settlement agreement also includes a $3.4 million retail natural gas rate decrease, which includes a deferral of $2.4 million of employee benefit costs that will be recovered in a future rate proceeding. The 2013 electric and natural gas rates were subject to downward adjustment based on updated December 31, 2012, pension and benefit cost estimates, which were filed with the PSCW on March 1, 2013. The settlement agreement reflects a 10.30% return on common equity and a common equity ratio of 51.61% in WPS's regulatory capital structure. In addition, WPS was authorized recovery of $5.9 million related to income tax amounts previously expensed due to the Federal Health Care Reform Act. As a result, this amount was recorded as a regulatory asset in 2012 and began being recovered from customers in 2013. The settlement agreement also authorized the recovery of direct Cross State Air Pollution Rule (CSAPR) costs incurred through the end of 2012. Lastly, the settlement agreement also authorized WPS to switch from production tax credits to Section 1603 Grants for the Crane Creek Wind Project.

A new decoupling mechanism for natural gas and electric residential and small commercial and industrial customers was approved as part of the settlement agreement on a pilot basis for 2013. The mechanism is based on total rate case-approved margins, rather than being calculated on a per-customer basis. The mechanism does not cover all customer classes, and it continues to include an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service. Amounts recoverable from or refundable to customers are subject to these caps and are included in rates upon approval in a rate proceeding.

2012 Rates

On December 9, 2011, the PSCW issued a final written order for WPS, effective January 1, 2012. It authorized an electric rate increase of $8.1 million and required a natural gas rate decrease of $7.2 million. The electric rate increase was driven by projected increases in fuel and purchased power costs. However, to the extent that actual fuel and purchased power costs exceeded a 2% price variance from costs included in rates, they were deferred for recovery or refund in a future rate proceeding. The rate order allowed for the netting of the 2010 electric decoupling under-collection with the 2011 electric decoupling over-collection, and reflected reduced contributions to the Focus on Energy Program. The rate order also allowed for the deferral of direct CSAPR compliance costs, including carrying costs.

Michigan

MGU Depreciation Case

In January 2013, the Michigan Court of Appeals issued an order reversing the MPSC's 2010 disallowance of $2.5 million associated with the early retirement of certain MGU assets. As a result, a $2.5 million reduction to depreciation expense was recorded in 2013. MGU has modified its depreciation study currently pending before the MPSC to reflect recovery of these previously disallowed costs. The deadline to appeal the Michigan Court of Appeals' order was March 7, 2013.

2012 UPPCO Rates

On December 20, 2011, the MPSC issued an order approving a settlement agreement for UPPCO authorizing a retail electric rate increase of $4.2 million, effective January 1, 2012. The new rates reflect a 10.20% return on common equity and a common equity ratio of 54.90% in UPPCO's regulatory capital structure. The order states that if UPPCO files a rate case in 2013, the earliest effective date for new final rates or self-implemented rates is January 1, 2014. Additionally, the order required UPPCO to terminate its existing decoupling mechanism, effective December 31, 2011, and replace it with a new decoupling mechanism based on total margins, beginning January 1, 2013. The new decoupling mechanism does not cover variations in volumes due to actual weather being different from rate case-assumed weather. It includes an annual 1.5% cap based on distribution revenues approved in the rate case. UPPCO had no decoupling mechanism in place during 2012.

In April 2012, the State of Michigan Court of Appeals ruled in a Detroit Edison proceeding that the MPSC did not have authority to approve electric decoupling mechanisms. This decision was not appealed. As a result of this ruling, UPPCO expensed $1.5 million in the first quarter of 2012 related to electric decoupling amounts previously deferred for regulatory recovery. However, in August 2012, the MPSC issued an order stating it had the authority to approve UPPCO's decoupling mechanism, as UPPCO's decoupling mechanism was authorized pursuant to an MPSC-approved settlement agreement. Therefore, in the third quarter of 2012, UPPCO reversed the $1.5 million previously expensed in the first quarter of 2012.

Illinois

2013 Rate Cases

On July 31, 2012, PGL and NSG filed applications with the ICC to increase retail natural gas rates $78.3 million and $9.8 million, respectively, with rates expected to be effective in July 2013. Both PGL's and NSG's requests reflect a 10.75% return on common equity and a target common equity ratio of 50.00% in their regulatory capital structures. In their briefs, PGL and NSG reflected revised increases of $97.0 million and $9.6 million, respectively, including a revised requested return on common equity of 10.00%. The revised request at PGL was primarily driven by increased costs due to new permitting and restoration requirements, as well as modifications in natural gas main and service pipe installation procedures.

In its reply brief, the ICC Staff recommended rate increases of $12.9 million and $3.4 million for PGL and NSG, respectively, as well as a 9.06% return on common equity for both companies. Their recommendation also included a common equity ratio of 50.43% and 50.32% in PGL's and NSG's regulatory capital structures, respectively. In the Illinois Attorney General's reply brief, it recommended rate increases not to exceed $15.4 million- and $2.6 million for PGL and NSG, respectively, and in its initial brief, adopted the Staff's return on equity recommendations.

On April 26, 2013, the Administrative Law Judges served their proposed order recommending rate increases of $52.0 million and $6.1 million for PGL and NSG, respectively. This reflects a 9.33% return on common equity for both companies. The proposed order included a common equity ratio of 50.43% and 50.32% in PGL's and NSG's regulatory capital structures, respectively.  Exception briefs and replies to the proposed order are due May 9, 2013 and May 16, 2013, respectively. The ICC will issue a final order in this proceeding no later than June 27, 2013.

2012 Rates

On January 10, 2012, the ICC issued a final order authorizing a retail natural gas rate increase of $57.8 million for PGL and $1.9 million for NSG, effective January 21, 2012. The rates for PGL reflected a 9.45% return on common equity and a common equity ratio of 49.00% in PGL's regulatory capital structure. The rates for NSG reflected a 9.45% return on common equity and a common equity ratio of 50.00% in NSG's regulatory capital structure. The rate order also approved a permanent decoupling mechanism.

The Illinois Attorney General appealed to the Illinois Appellate Court (Court) the ICC's authority to approve decoupling and filed a motion to stay the implementation of the permanent decoupling mechanism or make collections subject to refund. In May 2012, the ICC issued a revised amendatory order granting the Illinois Attorney General's motion to make revenues collected under the permanent decoupling mechanism subject to refund. Refunds would have been required if the Court found that the ICC did not have authority to approve decoupling and ordered a refund. As a result, the recovery of amounts related to decoupling in 2012 were uncertain, and PGL and NSG had established offsetting reserves equal to decoupling amounts accrued. In March 2013, the Court issued an opinion that affirmed the ICC's order approving the permanent decoupling mechanism. Therefore, PGL's and NSG's permanent decoupling mechanism is in place for 2013, and decoupling amounts recorded in 2012 and 2013 are expected to be recovered or refunded, absent an adverse decision on appeal at the Illinois Supreme Court. Between April 1, 2013 and December 31, 2013, PGL and NSG expect to recover $14.8 million and $1.7 million, respectively, related to their 2012 decoupling mechanisms.

Minnesota

2011 Rates

On July 13, 2012, the MPUC approved a written order for MERC authorizing a retail natural gas rate increase of $11.0 million, effective January 1, 2013. The new rates reflect a 9.70% return on common equity and a common equity ratio of 50.48% in MERC's regulatory capital structure. In addition, the order set recovery of MERC's 2011 test-year pension expense at 2010 levels. The MPUC also approved a decoupling mechanism for MERC that covers residential and small commercial and industrial customers on a three-year trial basis, effective January 1, 2013. The decoupling mechanism does not adjust for variations in volumes resulting from changes in customer count compared to rate case levels. It includes an annual 10% cap based on distribution revenues approved in the rate case. Amounts recoverable from or refundable to customers are subject to this cap.

Federal

Through a series of orders issued by the FERC, Regional Through and Out Rates for transmission service between the MISO and the PJM Interconnection were eliminated effective December 1, 2004. To compensate transmission owners for the revenue they would no longer receive due to this rate elimination, the FERC ordered a transitional pricing mechanism called the Seams Elimination Charge Adjustment (SECA) be put into place. Load-serving entities paid these SECA charges during a 16-month transition period from December 1, 2004, through March 31, 2006.

Integrys Energy Services initially expensed the majority of the total $19.2 million of billings received during the transitional period. The remaining amount was considered probable of recovery due to inconsistencies between the FERC's SECA order and the transmission owners' FERC-ordered compliance filings. Integrys Energy Services protested the FERC’s SECA order, and in August 2006, the Administrative Law Judge hearing the case issued an Initial Decision that was in substantial agreement with all of Integrys Energy Services' positions. In May 2010, the FERC ruled favorably for Integrys Energy Services on two issues, but reversed the rulings of the Initial Decision on nearly every other substantive issue. Integrys Energy Services and numerous other parties filed for rehearing of the FERC's order on the Initial Decision, which the FERC denied on September 30, 2011. The FERC has yet to issue an order on the compliance filings made by the transmission owners. Integrys Energy Services has appealed the adverse FERC decision to the U.S. Court of Appeals for the D.C. Circuit. As a result of the rulings received from the FERC in May 2010, Integrys Energy Services had a $3.8 million receivable recorded at March 31, 2013.

In January 2013, Integrys Energy Services reached a settlement with American Electric Power Service Corporation (AEP), and filed a Joint Stipulation and Agreement ("Settlement Agreement") with the FERC on January 10, 2013. If approved by the FERC, the Settlement Agreement will become effective on the date the FERC's order approving the Settlement Agreement becomes final and nonappealable. The Settlement Agreement provides that AEP would remit to Integrys Energy Services, in complete settlement of the matters at issue, a lump sum payment of $9.5 million within five business days of the effective date of the Settlement Agreement, and within five days of receipt of the lump sum payment, Integrys Energy Services would withdraw its petitions for review filed with the U.S. Court of Appeals for the D.C. Circuit.

XML

DISCONTINUED OPERATIONS (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended					1 Months Ended	3 Months Ended					1 Months Ended	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013 Combined Locks	Mar. 31, 2012 Combined Locks	Dec. 31, 2012 Combined Locks	Mar. 31, 2013 WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC	Mar. 31, 2013 WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC	Mar. 31, 2012 WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC	Mar. 14, 2013 WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC	Dec. 31, 2012 WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC	Mar. 31, 2013 WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC Integrys Energy Services	Nov. 30, 2012 WPS Westwood Generation, LLC	Mar. 31, 2012 WPS Westwood Generation, LLC
Assets and liabilities classified as held for sale on balance sheets
Inventories			$ 0.5		$ 0.5				$ 1.8	$ 1.8
Other current assets									0.2
Property, plant, and equipment, net of accumulated depreciation			2.0		2.0				5.7	5.7
Accumulated depreciation			0.5		0.5
Other long-term assets									0.1	0.1
Total assets			2.5		2.5				7.8	7.6
Other current liabilities									0.4	0.2
Carrying value of the derivative contract liabilities assumed by the buyer											6.8
Components of discontinued operations recorded in income statements
Nonregulated revenues				0.4			1.2	(0.7)					4.1
Nonregulated cost of sales			(0.1)	(0.3)			(0.9)	(0.4)					(1.3)
Operating and maintenance expense			(0.1)	(0.2)			0.4	(0.5)					(1.0)
Depreciation and amortization expense				(0.1)				(0.2)					(0.3)
Taxes other than income taxes				(0.1)			(0.3)	(0.8)					(0.1)
Interest expense													(0.1)
Income (loss) before taxes			(0.2)	(0.3)			0.4	(2.6)					1.3
(Provision) benefit for income taxes			0.1	0.1			(0.2)	1.0					(0.5)
Discontinued operations, net of tax	6.1	0.9	(0.1)	(0.2)			0.2	(1.6)					0.8
Gain on sale at closing							1.0
Earn-out mechanism period						4 years
Period for which transition services are provided						6 months						6 months
Period from the sale of discontinued operations within which cash flows will expire						2 years
Proceeds related to sale						1.6						2.6
Note receivable from the buyer												$ 4.0
Term of note receivable from the buyer												7 years 6 months

XML

COMMON EQUITY (Tables)

3 Months Ended

Mar. 31, 2013

COMMON EQUITY

Changes to issued common stock

Common stock at December 31, 2012	78,287,906
Shares issued
Stock Investment Plan	114,365
Stock-based compensation	317,677
Rabbi trust shares	90,000
Common stock at March 31, 2013	78,809,948

Summary of common stock activity to meet the requirements of the Stock Investment Plan and certain stock-based employee benefit and compensation plans

Period	Method of meeting requirements
Beginning 02/05/2013	Issuing new shares *
01/01/2012 – 02/04/2013	Purchased shares on the open market

^* These stock issuances increased equity $22.3 million in 2013.

Reconciliation of shares issued and outstanding

	March 31, 2013			December 31, 2012
	Shares	Average Cost *		Shares	Average Cost *
Common stock issued	78,809,948			78,287,906
Less:
Deferred compensation rabbi trust	456,852	$	48.23	385,439	$	46.03
Total common shares outstanding	78,353,096			77,902,467

* Based on our stock price on the day the shares entered the deferred compensation rabbi trust. Shares paid out of the trust are valued at the average cost of shares in the trust.

Computation of basic and diluted earnings per share

	Three Months Ended March 31
(Millions, except per share amounts)	2013			2012
Numerator:
Net income from continuing operations	$	182.2		$	98.8
Discontinued operations, net of tax	6.1			0.9
Preferred stock dividends of subsidiary	(0.8		)	(0.8		)
Net income attributed to common shareholders	$	187.5		$	98.9
Denominator:
Average shares of common stock — basic	78.7			78.6
Effect of dilutive securities
Stock-based compensation	0.4			0.4
Deferred compensation	0.2			0.2
Average shares of common stock — diluted	79.3			79.2
Earnings per common share
Basic	$	2.38		$	1.26
Diluted	2.37			1.25

Capital transactions with subsidiaries

During the three months ended March 31, 2013, capital transactions with subsidiaries were as follows (in millions):

Subsidiary	Dividends To Parent		Return Of  Capital To Parent		Equity Contributions From Parent
ITF (1)	$	—	$	—	$	11.7
MERC	—		21.0		—
WPS	27.1		—		200.0
WPS Investments, LLC (2)	17.3		—		1.7
Total	$	44.4	$	21.0	$	213.4

⁽¹⁾  ITF is a direct wholly owned subsidiary of PELLC. As a result, it makes distributions to PELLC, and receives equity contributions from PELLC. Subject to applicable law, PELLC does not have any dividend restrictions or limitations on distributions to us.

⁽²⁾  WPS Investments, LLC is a consolidated subsidiary that is jointly owned by us, WPS, and UPPCO. At March 31, 2013, we had an 85.86% ownership interest, while WPS and UPPCO had an 11.66% and 2.48% ownership interest, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2013, all equity contributions to WPS Investments, LLC were made solely by us.

XML

NEW ACCOUNTING PRONOUNCEMENTS

3 Months Ended

Mar. 31, 2013

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS

NOTE 23 — NEW ACCOUNTING PRONOUNCEMENTS

Recently Adopted Accounting Guidance

Accounting Standards Update (ASU) 2013-02, "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income," was issued in February 2013. This guidance requires disclosure of amounts reclassified out of accumulated other comprehensive income by component. Significant amounts are required to be presented by the respective line items of net income or should be cross-referenced to other disclosures. These disclosures may be presented on the income statement or in the notes to the financial statements. Adoption of this guidance resulted in the addition of Note 17, "Accumulated Other Comprehensive Loss."

ASU 2011-11, "Disclosures about Offsetting Assets and Liabilities," was issued in December 2011. The guidance requires enhanced disclosures about offsetting and related arrangements. ASU 2013-01, "Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities," was issued in January 2013. This guidance clarifies that the scope of ASU 2011-11 applies to certain derivatives included in the Derivatives and Hedging Topic of the FASB ASC. Adoption of the guidance resulted in new disclosures in Note 3, "Risk Management Activities."

ASU 2012-02, "Testing Indefinite-Lived Intangible Assets for Impairment," was issued in July 2012. This guidance gives companies an option to first perform a qualitative assessment to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired. If a company concludes that this is the case, the fair value of the indefinite-lived intangible asset must be determined, and a quantitative impairment test is required. Otherwise, a company can bypass the quantitative impairment test. Adoption of this guidance did not have an impact on our financial statements.

XML

CASH AND CASH EQUIVALENTS (Tables)

3 Months Ended

Mar. 31, 2013

CASH AND CASH EQUIVALENTS

Schedule of supplemental disclosure to statements of cash flows

	Three Months Ended March 31
(Millions)	2013			2012
Cash paid for interest	$	4.8		$	8.9
Cash received for income taxes	(1.0		)	(33.2		)

Schedule of significant noncash transactions

	Three Months Ended March 31
(Millions)	2013		2012
Construction costs funded through accounts payable	$	59.8	$	50.2
Equity issued for stock-based compensation plans	18.7		—
Equity issued for reinvested dividends	3.0		—
Risk management asset related to sale of Beaver Falls and Syracuse *	6.8		—

* See Note 5, "Discontinued Operations," for more information.

XML

FINANCIAL INFORMATION

3 Months Ended

Mar. 31, 2013

FINANCIAL INFORMATION

FINANCIAL INFORMATION

NOTE 1 — FINANCIAL INFORMATION

As used in these notes, the term “financial statements” refers to the condensed consolidated financial statements. This includes the condensed consolidated statements of income, condensed consolidated statements of comprehensive income, condensed consolidated balance sheets, and condensed consolidated statements of cash flows, unless otherwise noted. In this report, when we refer to “us,” “we,” “our,” or “ours,” we are referring to Integrys Energy Group, Inc.

We prepare our financial statements in conformity with the rules and regulations of the SEC for Quarterly Reports on Form 10-Q and in accordance with GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2012.

In management’s opinion, these unaudited financial statements include all adjustments necessary for a fair presentation of financial results. All adjustments are normal and recurring, unless otherwise noted. All intercompany transactions have been eliminated in consolidation. Financial results for an interim period may not give a true indication of results for the year.

XML

RISK MANAGEMENT ACTIVITIES (Tables)

3 Months Ended

Mar. 31, 2013

RISK MANAGEMENT ACTIVITIES

Assets and liabilities from risk management activities

		March 31, 2013
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Utility Segments
Nonhedge derivatives
Natural gas contracts	Current	$	9.8	$	3.7
Natural gas contracts	Long-term	1.9		—
Financial transmission rights (FTRs)	Current	1.0		0.1
Petroleum product contracts	Current	0.1		—
Coal contracts	Current	0.1		2.8
Coal contracts	Long-term	—		2.0
Cash flow hedges
Natural gas contracts	Current	—		0.1
Nonregulated Segments
Nonhedge derivatives
Natural gas contracts	Current	24.3		19.7
Natural gas contracts	Long-term	10.0		5.3
Electric contracts	Current	147.2		114.5
Electric contracts	Long-term	38.4		42.0
	Current	182.5		140.9
	Long-term	50.3		49.3
Total		$	232.8	$	190.2

*   We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

		December 31, 2012
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Utility Segments
Nonhedge derivatives
Natural gas contracts	Current	$	2.5	$	14.0
Natural gas contracts	Long-term	0.9		0.8
FTRs	Current	2.1		0.1
Petroleum product contracts	Current	0.2		—
Coal contracts	Current	0.3		4.7
Coal contracts	Long-term	2.2		4.3
Cash flow hedges
Natural gas contracts	Current	—		0.4
Nonregulated Segments
Nonhedge derivatives
Natural gas contracts	Current	51.7		48.5
Natural gas contracts	Long-term	11.5		7.6
Electric contracts	Current	88.6		114.2
Electric contracts	Long-term	30.7		45.7
	Current	145.4		181.9
	Long-term	45.3		58.4
Total		$	190.7	$	240.3

*   We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

Schedule of potential effect of netting arrangements on financial position for recognized derivative assets and liabilities

	March 31, 2013
(Millions)	Gross Amount		Gross Amount Not Offset in the Balance Sheet, including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements
Utility Segments	$	12.8	$	3.4	$	9.4
Nonregulated Segments	219.7		160.3		59.4
Total	232.5		163.7		68.8
Derivative assets not subject to master netting or similar arrangements	0.3				0.3
Total risk management assets	$	232.8			$	69.1
Derivative liabilities subject to master netting or similar arrangements
Utility Segments	$	3.9	$	3.4	$	0.5
Nonregulated Segments	181.4		160.3		21.1
Total	185.3		163.7		21.6
Derivative liabilities not subject to master netting or similar arrangements	4.9				4.9
Total risk management liabilities	$	190.2			$	26.5

	December 31, 2012
(Millions)	Gross Amount		Gross Amount Not Offset in the Balance Sheet, including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements
Utility Segments	$	5.7	$	3.0	$	2.7
Nonregulated Segments	182.5		145.4		37.1
Total	188.2		148.4		39.8
Derivative assets not subject to master netting or similar arrangements	2.5				2.5
Total risk management assets	$	190.7			$	42.3
Derivative liabilities subject to master netting or similar arrangements
Utility Segments	$	15.3	$	3.8	$	11.5
Nonregulated Segments	215.4		159.8		55.6
Total	230.7		163.6		67.1
Derivative liabilities not subject to master netting or similar arrangements	9.6				9.6
Total risk management liabilities	$	240.3			$	76.7

Cash collateral positions

(Millions)	March 31, 2013		December 31, 2012
Cash collateral provided to others:
Related to contracts under master netting or similar arrangements	$	24.3	$	39.9
Other	1.1		1.1
Cash collateral received from others related to contracts under master netting or similar arrangements *	—		0.2

*   Reflected in other current liabilities on the balance sheets.

Credit risk derivatives in a liability position

(Millions)	March 31, 2013		December 31, 2012
Integrys Energy Services	$	67.2	$	108.9
Utility segments	3.8		14.0

Collateral requirements related to credit-risk related contingent features in commodity instruments

(Millions)	March 31, 2013		December 31, 2012
Collateral that would have been required:
Integrys Energy Services	$	124.6	$	173.8
Utility segments	0.4		10.1
Collateral already satisfied:
Integrys Energy Services — Letters of credit	3.2		3.2
Collateral remaining:
Integrys Energy Services	121.4		170.6
Utility segments	0.4		10.1

Utility Segments, Notional volumes of outstanding nonhedge derivative contracts

	March 31, 2013			December 31, 2012
	Purchases	Sales	Other Transactions	Purchases	Sales	Other Transactions
Natural gas (millions of therms)	595.4	—	N/A	1,072.6	0.1	N/A
FTRs (millions of kilowatt-hours)	N/A	N/A	1,579.0	N/A	N/A	4,057.2
Petroleum products (barrels)	50,855.0	N/A	N/A	62,811.0	N/A	N/A
Coal contracts (millions of tons)	4.7	0.2	N/A	5.1	N/A	N/A

Utility Segments, Unrealized gains (losses) related to nonhedge derivatives at the utilities

		Three Months Ended March 31
(Millions)	Financial Statement Presentation	2013			2012
Natural gas contracts	Balance Sheet — Regulatory assets (current)	$	13.0		$	(6.4	)
Natural gas contracts	Balance Sheet — Regulatory assets (long-term)	0.8			(0.8		)
Natural gas contracts	Balance Sheet — Regulatory liabilities (current)	5.9			(3.7		)
Natural gas contracts	Balance Sheet — Regulatory liabilities (long-term)	0.8			0.1
Natural gas contracts	Income Statement — Utility cost of fuel, natural gas, and purchased power	—			0.1
Natural gas contracts	Income Statement — Operating and maintenance expense	0.2			—
FTRs	Balance Sheet — Regulatory assets (current)	0.2			0.4
FTRs	Balance Sheet — Regulatory liabilities (current)	(0.4		)	(0.3		)
Petroleum product contracts	Balance Sheet — Regulatory assets (current)	—			0.1
Petroleum product contracts	Balance Sheet — Regulatory liabilities (current)	—			0.1
Petroleum product contracts	Income Statement — Operating and maintenance expense	—			0.1
Coal contracts	Balance Sheet — Regulatory assets (current)	1.9			(3.1		)
Coal contracts	Balance Sheet — Regulatory assets (long-term)	2.3			(3.5		)
Coal contracts	Balance Sheet — Regulatory liabilities (current)	(0.2		)	—
Coal contracts	Balance Sheet — Regulatory liabilities (long-term)	(2.2		)	—

Nonregulated Segments, Notional volumes of outstanding nonhedge derivative contracts

	March 31, 2013		December 31, 2012
(Millions)	Purchases	Sales	Purchases	Sales
Commodity contracts
Natural gas (therms)	641.5	556.2	782.0	679.0
Electric (kilowatt-hours)	56,100.1	34,502.0	54,127.6	31,809.6
Foreign exchange contracts (Canadian dollars)	0.4	0.4	0.4	0.4

Nonregulated Segments, gains (losses) related to nonhedge derivatives

		Three Months Ended March 31
(Millions)	Income Statement Presentation	2013			2012
Natural gas contracts	Nonregulated revenue	$	3.4		$	4.0
Natural gas contracts	Nonregulated cost of sales	(1.6		)	—
Natural gas contracts	Nonregulated revenue (reclassified from accumulated OCI) *	(0.1		)	(1.2		)
Electric contracts	Nonregulated revenue	64.0			(68.6		)
Electric contracts	Nonregulated revenue (reclassified from accumulated OCI) *	(1.0		)	(0.7		)
Total		$	64.7		$	(66.5	)

* Represents amounts reclassified from accumulated OCI related to cash flow hedges that were dedesignated in prior periods.

XML

FAIR VALUE (Details 5) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
Carrying value and estimated fair value of financial instruments
Impact on earnings of unrealized gains and losses on Level 3 derivatives	$ 0
Long-term debt	2,223.2	2,245.2
Preferred stock of subsidiary	51.1	51.1
Carrying Amount
Carrying value and estimated fair value of financial instruments
Long-term debt	2,223.2	2,245.2
Preferred stock of subsidiary	51.1	51.1
Total, Fair value
Carrying value and estimated fair value of financial instruments
Long-term debt	2,376.2	2,425.8
Preferred stock of subsidiary	$ 61.7	$ 52.7

XML

COMMITMENTS AND CONTINGENCIES (Tables)

3 Months Ended

Mar. 31, 2013

COMMITMENTS AND CONTINGENCIES

Schedule of minimum future commitments related to purchase obligations

				Payments Due By Period
(Millions)	Date Contracts Extend Through	Total Amounts Committed		2013		2014		2015		2016		2017		Later Years
Natural gas utility supply and transportation	2028	$	823.2	$	124.9	$	156.3	$	137.9	$	125.7	$	86.9	$	191.5
Electric utility
Purchased power	2029	852.6		121.3		37.7		33.0		29.4		28.4		602.8
Coal supply and transportation	2017	122.7		44.4		41.2		30.4		6.2		0.5		—
Nonregulated electricity and natural gas supply	2020	830.6		479.8		305.9		34.3		4.6		1.3		4.7
Total		$	2,629.1	$	770.4	$	541.1	$	235.6	$	165.9	$	117.1	$	799.0

XML

RISK MANAGEMENT ACTIVITIES (Details 5) (Nonregulated Segments) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013 USD ($)	Mar. 31, 2012 USD ($)	Mar. 31, 2013 Natural gas contracts Nonregulated revenue USD ($)	Mar. 31, 2012 Natural gas contracts Nonregulated revenue USD ($)	Mar. 31, 2013 Natural gas contracts Nonregulated revenue (reclassified from accumulated OCI) USD ($)	Mar. 31, 2012 Natural gas contracts Nonregulated revenue (reclassified from accumulated OCI) USD ($)	Mar. 31, 2013 Natural gas contracts Nonregulated cost of sales USD ($)	Mar. 31, 2013 Electric contracts Nonregulated revenue USD ($)	Mar. 31, 2012 Electric contracts Nonregulated revenue USD ($)	Mar. 31, 2013 Electric contracts Nonregulated revenue (reclassified from accumulated OCI) USD ($)	Mar. 31, 2012 Electric contracts Nonregulated revenue (reclassified from accumulated OCI) USD ($)	Mar. 31, 2013 Cash flow hedges Natural gas contracts USD ($)	Mar. 31, 2013 Cash flow hedges Electric contracts USD ($)	Mar. 31, 2013 Purchases Natural gas contracts therm	Dec. 31, 2012 Purchases Natural gas contracts therm	Mar. 31, 2013 Purchases Electric contracts kWh	Dec. 31, 2012 Purchases Electric contracts kWh	Mar. 31, 2013 Purchases Foreign exchange contracts CAD	Dec. 31, 2012 Purchases Foreign exchange contracts CAD	Mar. 31, 2013 Sales Natural gas contracts therm	Dec. 31, 2012 Sales Natural gas contracts therm	Mar. 31, 2013 Sales Electric contracts kWh	Dec. 31, 2012 Sales Electric contracts kWh	Mar. 31, 2013 Sales Foreign exchange contracts CAD	Dec. 31, 2012 Sales Foreign exchange contracts CAD
Risk management activities
Notional volume of outstanding non-hedge derivative contracts														641,500,000	782,000,000					556,200,000	679,000,000
Notional volume of outstanding non-hedge derivative contracts																56,100,100,000	54,127,600,000					34,502,000,000	31,809,600,000
Notional volume of outstanding foreign exchange non-hedge derivative contracts, monetary (in Canadian dollars)																		0.4	0.4					0.4	0.4
Gains (losses) recorded related to non-hedge derivatives					(0.1)	(1.2)				(1.0)	(0.7)
Gains (losses) recorded related to non-hedge derivatives			3.4	4.0			(1.6)	64.0	(68.6)
Gains (losses) recorded related to non-hedge derivatives	64.7	(66.5)
Pre-tax losses on cash flow hedge expected to be recognized in earnings in the next 12 months												$ (0.1)	$ (2.4)

XML

COMMON EQUITY (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
Changes to issued common stock
Common stock issued, balance at the beginning of the period	78,287,906
Shares issued - Stock Investment Plan	114,365
Shares issued - Stock-based compensation	317,677
Shares issued - Rabbi trust Shares	90,000
Common stock issued, balance at the end of the period	78,809,948	78,287,906
Issuance of common stock under stock investment plan and stock-based compensation plans	$ 22.3
Reconciliation of shares outstanding
Common stock, shares issued	78,809,948	78,287,906
Deferred compensation rabbi trust (in shares)	456,852	385,439
Total common shares outstanding	78,353,096	77,902,467
Average cost of shares in the rabbi trust (in dollars per share)	$ 48.23	$ 46.03

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Utility revenues	$ 1,123.8	$ 971.0
Nonregulated revenues	554.4	276.9
Total revenues	1,678.2	1,247.9
Utility cost of fuel, natural gas, and purchased power	565.1	472.3
Nonregulated cost of sales	436.8	273.7
Operating and maintenance expense	295.1	259.3
Depreciation and amortization expense	60.9	62.1
Taxes other than income taxes	27.2	27.4
Operating income	293.1	153.1
Earnings from equity method investments	22.3	21.1
Miscellaneous income	5.7	2.4
Interest expense	(29.3)	(30.4)
Other expense	(1.3)	(6.9)
Income before taxes	291.8	146.2
Provision for income taxes	109.6	47.4
Net income from continuing operations	182.2	98.8
Discontinued operations, net of tax	6.1	0.9
Net income	188.3	99.7
Preferred stock dividends of subsidiary	(0.8)	(0.8)
Net income attributed to common shareholders	$ 187.5	$ 98.9
Average shares of common stock
Basic (in shares)	78.7	78.6
Diluted (in shares)	79.3	79.2
Earnings per common share (basic)
Net income from continuing operations (in dollars per share)	$ 2.30	$ 1.25
Discontinued operations, net of tax (in dollars per share)	$ 0.08	$ 0.01
Earnings per common share (basic) (in dollars per share)	$ 2.38	$ 1.26
Earnings per common share (diluted)
Net income from continuing operations (in dollars per share)	$ 2.29	$ 1.24
Discontinued operations, net of tax (in dollars per share)	$ 0.08	$ 0.01
Earnings per common share (diluted) (in dollars per share)	$ 2.37	$ 1.25
Dividends per common share declared (in dollars per share)	$ 0.68	$ 0.68

XML

ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)

3 Months Ended

Mar. 31, 2013

ACCUMULATED OTHER COMPREHENSIVE LOSS

Schedule of changes, net of tax, in accumulated other comprehensive loss

	Cash Flow Hedges			Defined Benefit Pension Plans			Accumulated Other Comprehensive Income (Loss)
Beginning balance at December 31, 2012	$	(5.2	)	$	(35.7	)	$	(40.9	)
Other comprehensive income before reclassifications	0.1			—			0.1
Amounts reclassified out of accumulated other comprehensive loss	0.9			0.6			1.5
Net current period other comprehensive income	1.0			0.6			1.6
Ending balance at March 31, 2013	$	(4.2	)	$	(35.1	)	$	(39.3	)

Schedule of reclassifications out of accumulated other comprehensive loss

The following table shows the reclassifications out of accumulated other comprehensive loss during the three months ended March 31, 2013:

	Amount Reclassified			Affected Line Item in the Statements of Income
Losses on cash flow hedges
Utility commodity derivative contracts	$	0.2		Operating and maintenance expense(1)
Non-regulated commodity derivative contracts	1.1			Nonregulated revenues
Interest rate hedges	0.2			Interest expense
	1.5			Total before tax
	0.6			Tax expense
	0.9			Net of tax
Defined benefit pension plans
Amortization of prior service costs	(0.1		)	(2)
Amortization of actuarial losses	1.1			(2)
	1.0			Total before tax
	0.4			Tax expense
	0.6			Net of tax
Total reclassifications	$	1.5

⁽¹⁾  Changes in the price of natural gas used to support utility operations is not a component of the natural gas costs recovered from customers on a one-for-one basis.

⁽²⁾  These items are included in the computation of net periodic benefit cost. See Note 14, "Employee Benefit Plans," for additional information.

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
CONDENSED CONSOLIDATED BALANCE SHEETS
Accounts receivable and accrued unbilled revenues, reserves (in dollars)	$ 47.2	$ 43.5
Property, plant, and equipment, accumulated depreciation (in dollars)	$ 3,225.5	$ 3,114.7
Common stock, par value (in dollars per share)	$ 1
Common stock, shares authorized	200,000,000
Common stock, shares issued	78,809,948	78,287,906
Common stock, shares outstanding	78,353,096	77,902,467
Preferred stock of subsidiary, par value (in dollars per share)	$ 100
Preferred stock of subsidiary, shares authorized	1,000,000
Preferred stock of subsidiary, shares issued	511,882
Preferred stock of subsidiary, shares outstanding	510,495

XML

INVENTORIES (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013
INVENTORIES
Temporary LIFO liquidation credit	$ 83.2

XML

INVESTMENT IN ATC (Tables) (ATC)

3 Months Ended

Mar. 31, 2013

ATC

Schedule of Equity Method Investments

Schedule of changes to Integrys Energy Group's investment in ATC

	Three Months Ended March 31
(Millions)	2013		2012
Balance at the beginning of period	$	476.6	$	439.4
Add: Earnings from equity method investment	21.7		20.8
Add: Capital contributions	1.7		3.4
Less: Dividends received	17.3		16.7
Balance at the end of period	$	482.7	$	446.9

Summarized income statement information of ATC

	Three Months Ended March 31
(Millions)	2013		2012
Income statement data
Revenues	$	151.8	$	147.7
Operating expenses	69.8		69.6
Other expense	21.5		20.0
Net income	$	60.5	$	58.1

Summarized balance sheet information of ATC

(Millions)	March 31, 2013		December 31, 2012
Balance sheet data
Current assets	$	69.3	$	63.1
Noncurrent assets	3,325.3		3,274.7
Total assets	$	3,394.6	$	3,337.8
Current liabilities	$	261.5	$	251.5
Long-term debt	1,550.0		1,550.0
Other noncurrent liabilities	124.8		95.8
Shareholders’ equity	1,458.3		1,440.5
Total liabilities and shareholders’ equity	$	3,394.6	$	3,337.8

XML

COMMITMENTS AND CONTINGENCIES (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013
Unconditional purchase obligations
Total Amounts Committed	$ 2,629.1
2013	770.4
2014	541.1
2015	235.6
2016	165.9
2017	117.1
Later Years	799.0
Natural gas supply and transportation | Natural Gas Utility
Unconditional purchase obligations
Total Amounts Committed	823.2
2013	124.9
2014	156.3
2015	137.9
2016	125.7
2017	86.9
Later Years	191.5
Purchased power | Electric Utility
Unconditional purchase obligations
Total Amounts Committed	852.6
2013	121.3
2014	37.7
2015	33.0
2016	29.4
2017	28.4
Later Years	602.8
Coal supply and transportation | Electric Utility
Unconditional purchase obligations
Total Amounts Committed	122.7
2013	44.4
2014	41.2
2015	30.4
2016	6.2
2017	0.5
Electricity and natural gas supply | Nonutility and Nonregulated Operations
Unconditional purchase obligations
Total Amounts Committed	830.6
2013	479.8
2014	305.9
2015	34.3
2016	4.6
2017	1.3
Later Years	4.7
Purchase orders
Purchase and sales commitments
Supply contract obligation amount	$ 713.5

XML

STOCK-BASED COMPENSATION

3 Months Ended

Mar. 31, 2013

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION

NOTE 15 — STOCK-BASED COMPENSATION

The following table reflects the stock-based compensation expense and the related deferred tax benefit recognized in income for the three months ended March 31:

(Millions)	2013		2012
Stock options	$	0.4	$	0.4
Performance stock rights	2.2		1.2
Restricted share units	2.8		2.1
Nonemployee director deferred stock units	0.3		1.0
Total stock-based compensation expense	$	5.7	$	4.7
Deferred income tax benefit	$	2.3	$	1.9

No stock-based compensation cost was capitalized during the three months ended March 31, 2013 and 2012.

Stock Options

The fair value of stock option awards granted is estimated using a binomial lattice model. The expected term of option awards is calculated based on historical exercise behavior and represents the period of time that options are expected to be outstanding. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. Our expected stock price volatility is estimated using its 10-year historical volatility. The following table shows the weighted-average fair value per stock option granted during the three months ended March 31, 2013, along with the assumptions incorporated into the valuation model:

	February 2013 Grant
Weighted-average fair value per option	$6.03
Expected term	5 years
Risk-free interest rate	0.18% – 2.11%
Expected dividend yield	5.33%
Expected volatility	24%

A summary of stock option activity for the three months ended March 31, 2013, and information related to outstanding and exercisable stock options at March 31, 2013, is presented below:

	Stock Options		Weighted-Average Exercise Price Per Share		Weighted-Average Remaining  Contractual Life (in Years)	Aggregate Intrinsic Value (Millions)
Outstanding at December 31, 2012	2,046,355		$	49.25
Granted	319,234		56.00
Exercised	(145,955	)	44.03
Outstanding at March 31, 2013	2,219,634		$	50.56	6.01	$	16.9
Exercisable at March 31, 2013	1,463,836		$	49.78	4.56	$	12.4

The aggregate intrinsic value for outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they all exercised their options at March 31, 2013. This is calculated as the difference between our closing stock price on March 31, 2013, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the three months ended March 31, 2013, and 2012, was $1.9 million and $2.0 million, respectively. The actual tax benefit realized for the tax deductions from these option exercises was not significant for the three months ended March 31, 2013, and 2012.

As of March 31, 2013, $2.6 million of compensation cost related to unvested and outstanding stock options was expected to be recognized over a weighted-average period of 2.0 years.

Performance Stock Rights

The fair values of performance stock rights are estimated using a Monte Carlo valuation model. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. The expected volatility is estimated using two to three years of historical data. The table below reflects the assumptions used in the valuation of the outstanding grants at March 31:

	2013
Risk-free interest rate	0.17% – 1.27%
Expected dividend yield	5.18% – 5.34%
Expected volatility	19% – 36%

A summary of the activity for the three months ended March 31, 2013, related to performance stock rights accounted for as equity awards is presented below:

	Performance Stock Rights		Weighted-Average Fair Value *
Outstanding at December 31, 2012	108,314		$	65.38
Granted	22,636		48.50
Distributed	(94,758	)	72.36
Adjustment for final payout	21,867		72.36
Outstanding at March 31, 2013	58,059		$	50.04

* Reflects the weighted-average fair value used to measure equity awards. Equity awards are measured using the grant date fair value or the fair value on the modification date.

The weighted-average grant date fair value of performance stock rights awarded during the three months ended March 31, 2013, and 2012, was $48.50 and $52.70, per performance stock right, respectively.

A summary of the activity for the three months ended March 31, 2013, related to performance stock rights accounted for as liability awards is presented below:

	Performance Stock Rights
Outstanding at December 31, 2012	189,093
Granted	90,496
Distributed	(61,753	)
Adjustment for final payout	14,255
Outstanding at March 31, 2013	232,091

The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of March 31, 2013, was $48.06 per performance stock right.

As of March 31, 2013, $5.9 million of compensation cost related to unvested and outstanding performance stock rights (equity and liability awards) was expected to be recognized over a weighted-average period of 1.5 years.

The total intrinsic value of performance stock rights distributed during the three months ended March 31, 2013, and 2012, was $8.8 million and $4.7 million, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance stock rights during the three months ended March 31, 2013, and 2012, was $3.6 million and $1.9 million, respectively.

Restricted Share Units

A summary of the activity related to all restricted share unit awards (equity and liability awards) for the three months ended March 31, 2013, is presented below:

	Restricted Share Unit Awards		Weighted-AverageGrant Date Fair Value
Outstanding at December 31, 2012	505,690		$	48.38
Granted	189,094		56.00
Dividend equivalents	5,818		52.20
Vested and released	(204,072	)	46.28
Forfeited	(1,507	)	48.47
Outstanding at March 31, 2013	495,023		$	52.20

As of March 31, 2013, $17.4 million of compensation cost related to these awards was expected to be recognized over a weighted-average period of 2.5 years.

The total intrinsic value of restricted share unit awards vested and released during the three months ended March 31, 2013, and 2012, was $11.4 million and $10.4 million, respectively. The actual tax benefit realized for the tax deductions from the vesting and release of restricted share units during the three months ended March 31, 2013, and 2012, was $4.6 million and $4.2 million, respectively.

The weighted-average grant date fair value of restricted share units awarded during the three months ended March 31, 2013, and 2012, was $56.00 and $53.24 per share, respectively.

Nonemployee Directors Deferred Stock Units

Each nonemployee director is granted deferred stock units (DSUs), typically in January of each year. The number of DSUs granted is calculated by dividing a set dollar amount by our closing common stock price on the date of the grant. Prior to January 1, 2013, under the terms of the agreement, these awards vested immediately, and therefore were expensed on the grant date. Beginning in 2013, these awards will generally vest over one year. Therefore, the expense for these awards will be recognized pro-rata over the year in which the grant occurs.

XML

GOODWILL AND OTHER INTANGIBLE ASSETS (Tables)

3 Months Ended

Mar. 31, 2013

GOODWILL AND OTHER INTANGIBLE ASSETS

Identifiable intangible assets other than goodwill

	March 31, 2013							December 31, 2012
(Millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets
Customer-related (1)	$	22.4	$	(15.0	)	$	7.4	$	22.4	$	(14.7	)	$	7.7
Contractual service agreements (2)	15.6		—			15.6		—		—			—
Patents/intellectual property (3)	7.2		(0.3		)	6.9		7.2		(0.3		)	6.9
Compressed natural gas fueling contract assets (4)	5.6		(1.7		)	3.9		5.6		(1.3		)	4.3
Renewable energy credits (5)	5.1		—			5.1		3.1		—			3.1
Nonregulated easements (6)	3.8		(1.0		)	2.8		3.8		(0.9		)	2.9
Customer-owned equipment modifications (7)	4.0		(0.6		)	3.4		4.0		(0.5		)	3.5
Other	0.5		(0.3		)	0.2		0.5		(0.2		)	0.3
Total	$	64.2	$	(18.9	)	$	45.3	$	46.6	$	(17.9	)	$	28.7
Unamortized intangible assets
MGU trade name	$	5.2	$	—		$	5.2	$	5.2	$	—		$	5.2
Trillium trade name	3.5		—			3.5		3.5		—			3.5
Pinnacle trade name	1.5		—			1.5		1.5		—			1.5
Total intangible assets	$	74.4	$	(18.9	)	$	55.5	$	56.8	$	(17.9	)	$	38.9

⁽¹⁾  Represents customer relationship assets associated with PELLC’s former nonregulated retail natural gas and electric operations and Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) compressed natural gas fueling operations. The remaining weighted-average amortization period for customer-related intangible assets at March 31, 2013, was approximately 9 years.

⁽²⁾  Represents contractual service agreements related to maintenance on the combustion turbine generators at the Fox Energy Center. The remaining amortization period for these intangible assets at March 31, 2013, was approximately 7 years.

⁽³⁾  Represents the fair value of patents/intellectual property at Pinnacle related to a system for more efficiently compressing natural gas to allow for faster fueling. The remaining amortization period at March 31, 2013, was approximately 9 years.

⁽⁴⁾  Represents the fair value of Trillium and Pinnacle contracts acquired in September 2011. The remaining amortization period at March 31, 2013, was approximately 8 years.

⁽⁵⁾  Used at Integrys Energy Services to comply with state Renewable Portfolio Standards and to support customer commitments.

⁽⁶⁾  Relates to easements supporting a pipeline at Integrys Energy Services. The easements are amortized on a straight-line basis, with a remaining amortization period at March 31, 2013, of approximately 11 years.

⁽⁷⁾  Relates to modifications made by Integrys Energy Services and Trillium to customer-owned equipment. These intangible assets are amortized on a straight-line basis, with a remaining weighted-average amortization period at March 31, 2013, of approximately 11 years.

Intangible asset amortization expense for the next five fiscal years

	For the Year Ending December 31
(Millions)	2013		2014		2015		2016		2017
Amortization to be recorded in nonregulated cost of sales	$	6.7	$	1.2	$	1.1	$	0.9	$	0.9
Amortization to be recorded in depreciation and amortization expense	3.8		4.1		4.1		3.9		3.8

XML

ACCUMULATED OTHER COMPREHENSIVE LOSS

3 Months Ended

Mar. 31, 2013

ACCUMULATED OTHER COMPREHENSIVE LOSS

ACCUMULATED OTHER COMPREHENSIVE LOSS

NOTE 17 — ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table shows the changes, net of tax, to our accumulated other comprehensive loss from December 31, 2012 through March 31, 2013:

	Cash Flow Hedges			Defined Benefit Pension Plans			Accumulated Other Comprehensive Income (Loss)
Beginning balance at December 31, 2012	$	(5.2	)	$	(35.7	)	$	(40.9	)
Other comprehensive income before reclassifications	0.1			—			0.1
Amounts reclassified out of accumulated other comprehensive loss	0.9			0.6			1.5
Net current period other comprehensive income	1.0			0.6			1.6
Ending balance at March 31, 2013	$	(4.2	)	$	(35.1	)	$	(39.3	)

The following table shows the reclassifications out of accumulated other comprehensive loss during the three months ended March 31, 2013:

	Amount Reclassified			Affected Line Item in the Statements of Income
Losses on cash flow hedges
Utility commodity derivative contracts	$	0.2		Operating and maintenance expense(1)
Non-regulated commodity derivative contracts	1.1			Nonregulated revenues
Interest rate hedges	0.2			Interest expense
	1.5			Total before tax
	0.6			Tax expense
	0.9			Net of tax
Defined benefit pension plans
Amortization of prior service costs	(0.1		)	(2)
Amortization of actuarial losses	1.1			(2)
	1.0			Total before tax
	0.4			Tax expense
	0.6			Net of tax
Total reclassifications	$	1.5

⁽¹⁾  Changes in the price of natural gas used to support utility operations is not a component of the natural gas costs recovered from customers on a one-for-one basis.

⁽²⁾  These items are included in the computation of net periodic benefit cost. See Note 14, "Employee Benefit Plans," for additional information.

XML

EMPLOYEE BENEFITS PLANS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Pension Benefits
Components of net periodic benefit cost
Service cost	$ 7.5	$ 12.4
Interest cost	17.8	19.8
Expected return on plan assets	(26.6)	(27.1)
Amortization of prior service cost (credit)	1.0	1.2
Amortization of net actuarial loss	13.5	8.3
Net periodic benefit cost	13.2	14.6
Contribution to the plans	63.2
Additional contributions to plans during the remainder of fiscal year	4.7
Other Benefits
Components of net periodic benefit cost
Service cost	6.5	5.5
Interest cost	6.3	7.2
Expected return on plan assets	(7.7)	(7.0)
Amortization of transition obligation		0.1
Amortization of prior service cost (credit)	(0.6)	(0.9)
Amortization of net actuarial loss	2.0	1.6
Net periodic benefit cost	6.5	6.5
Additional contributions to plans during the remainder of fiscal year	$ 32.8

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Operating Activities
Net income	$ 188.3	$ 99.7
Adjustments to reconcile net income to net cash provided by operating activities
Discontinued operations, net of tax	(6.1)	(0.9)
Depreciation and amortization expense	60.9	62.1
Recoveries and refunds of regulatory assets and liabilities	16.5	9.5
Net unrealized (gains) losses on energy contracts	(65.2)	43.7
Bad debt expense	9.3	10.1
Pension and other postretirement expense	15.9	17.5
Pension and other postretirement contributions	(63.2)	(246.2)
Deferred income taxes and investment tax credits	68.3	29.7
Equity income, net of dividends	(4.4)	(3.8)
Termination of tolling agreement with Fox Energy Company LLC	(50.0)
Other	6.3	2.7
Changes in working capital
Collateral on deposit	15.4	(13.7)
Accounts receivable and accrued unbilled revenues	(182.8)	49.8
Inventories	137.9	133.0
Other current assets	45.4	54.6
Accounts payable	24.7	(77.7)
Temporary LIFO liquidation credit	83.2	36.7
Other current liabilities	19.2	18.0
Net cash provided by operating activities	319.6	224.8
Investing Activities
Capital expenditures	(147.0)	(123.0)
Proceeds from the sale or disposal of assets	1.1	1.4
Capital contributions to equity method investments	(1.7)	(10.4)
Acquisition of Fox Energy Company LLC	(391.6)
Grant received related to Crane Creek Wind Project	69.0
Other	(3.0)	(4.6)
Net cash used for investing activities	(473.2)	(136.6)
Financing Activities
Short-term debt, net	74.0	2.2
Borrowing on term credit facility	200.0
Repayment of long-term debt	(22.0)
Proceeds from stock option exercises	6.4	10.1
Shares purchased for stock-based compensation	(2.0)	(24.6)
Payment of dividends
Preferred stock of subsidiary	(0.8)	(0.8)
Common stock	(50.1)	(53.0)
Payments made on derivative contracts related to divestitures classified as financing activities	(3.8)	(9.0)
Other	(4.5)	0.2
Net cash provided by (used for) financing activities	197.2	(74.9)
Change in cash and cash equivalents - continuing operations	43.6	13.3
Change in cash and cash equivalents - discontinued operations
Net cash (used for) provided by operating activities	(0.6)	1.0
Net cash provided by (used for) investing activities	1.6	(0.1)
Net change in cash and cash equivalents	44.6	14.2
Cash and cash equivalents at beginning of period	27.4	28.1
Cash and cash equivalents at end of period	$ 72.0	$ 42.3

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income	$ 188.3	$ 99.7
Cash flow hedges
Unrealized net gains (losses) arising during period, net of tax of $ - million and $(0.2) million, respectively	0.1	(0.3)
Reclassification of net losses to net income, net of tax of $0.6 million and $1.0 million, respectively	0.9	1.5
Cash flow hedges, net	1.0	1.2
Defined benefit pension plans
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.4 million and $0.3 million, respectively	0.6	0.3
Other comprehensive income, net of tax	1.6	1.5
Comprehensive income	189.9	101.2
Preferred stock dividends of subsidiary	(0.8)	(0.8)
Comprehensive income attributed to common shareholders	$ 189.1	$ 100.4

XML

LONG-TERM DEBT

3 Months Ended

Mar. 31, 2013

LONG-TERM DEBT

LONG-TERM DEBT

NOTE 10 — LONG-TERM DEBT

(Millions)	March 31, 2013			December 31, 2012
WPS (1)	$	850.1		$	872.1
PGL (2)	625.0			625.0
NSG (3)	74.5			74.5
Integrys Energy Group	674.8			674.8
Total	2,224.4			2,246.4
Unamortized discount on debt	(1.2		)	(1.2		)
Total debt	2,223.2			2,245.2
Less current portion	(291.5		)	(313.5		)
Total long-term debt	$	1,931.7		$	1,931.7

⁽¹⁾  In February 2013, WPS’s $22.0 million of 3.95% Senior Notes matured, and the outstanding principal balance was repaid.

In December 2013, WPS’s 4.80% Senior Notes will mature. As a result, the $125.0 million balance of these notes was included in the current portion of long-term debt on our balance sheets.

⁽²⁾  In April 2013, PGL bought back its $50.0 million of 5.00% Series KK First and Refunding Mortgage Bonds that were due in February 2033.

In the same month, PGL issued $50.0 million of 4.00% Series ZZ First and Refunding Mortgage Bonds. These bonds are due in February 2033.

On May 1, 2013, PGL’s 4.625% Series NN-2 First and Refunding Mortgage Bonds matured, and the outstanding principal balance was repaid. As a result, the $75.0 million balance of these bonds was included in the current portion of long-term debt on our balance sheets.

In November 2013, PGL’s 7.00% Series SS First and Refunding Mortgage Bonds will mature. As a result, the $45.0 million balance of these bonds was included in the current portion of long-term debt on our balance sheets.

⁽³⁾  On May 1, 2013, NSG issued $54.0 million of 3.96% Series Q First Mortgage Bonds. These bonds are due in May 2043.

On May 1, 2013, NSG’s 4.625% Series N-2 First Mortgage Bonds matured, and the outstanding principal balance was repaid. As a result, the $40.0 million balance of these bonds was included in the current portion of long-term debt on our balance sheets.

In November 2013, NSG’s 7.00% Series O First Mortgage Bonds will mature. As a result, the $6.5 million balance of these bonds was included in the current portion of long-term debt on our balance sheets.

On May 1, 2013, PGL secured commitments for $220.0 million of 30-year 3.96% Series AAA First and Refunding Mortgage Bonds with a delayed draw feature. These bonds will be issued in August 2013.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2013	Apr. 26, 2013
Document and Entity Information
Entity Registrant Name	INTEGRYS ENERGY GROUP, INC.
Entity Central Index Key	0000916863
Document Type	10-Q
Document Period End Date	Mar. 31, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		79,128,089
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1

XML

INCOME TAXES

3 Months Ended

Mar. 31, 2013

INCOME TAXES

INCOME TAXES

NOTE 11 — INCOME TAXES

We calculate our interim period provision for income taxes based on our projected annual effective tax rate as adjusted for certain discrete items.

The table below shows our effective tax rates:

	Three Months Ended March 31
	2013		2012
Effective Tax Rate	37.6	%	32.4	%

Our effective tax rate normally differs from the federal statutory tax rate of 35% due to additional provision for multistate income tax obligations. Other significant items that had an impact on our effective tax rates are noted below.

Our effective tax rate for the three months ended March 31, 2012, was lowered by the federal income tax benefit of wind production tax credits (PTCs). The effective income tax rate in 2013 was not impacted by wind PTCs. In the fourth quarter of 2012, we elected to claim and subsequently received a Section 1603 Grant for WPS's Crane Creek Wind Project in lieu of wind PTCs.

Our effective tax rate for the three months ended March 31, 2012, was also lowered by the effective settlement of certain state income tax examinations and a remeasurement of uncertain tax positions included in our liability for unrecognized tax benefits.

During the three months ended March 31, 2013, we decreased our liability for unrecognized tax benefits by $6.8 million. This decrease primarily related to a remeasurement of uncertain tax positions driven by an effective settlement of 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.

XML

FAIR VALUE (Details 2) (Nonregulated Segments, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Natural gas contracts
Transfers between the levels of the fair value hierarchy
Transfers into Level 2 from Level 3		$ 1.3
Transfers into Level 3 from Level 2	0.2	2.4
Electric contracts
Transfers between the levels of the fair value hierarchy
Transfers into Level 2 from Level 3	5.5	(0.1)
Transfers into Level 3 from Level 2		$ (5.0)

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Unrealized net gains (losses) arising during period, tax		$ (0.2)
Reclassification of net losses to net income, tax	0.6	1.0
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, tax	$ 0.4	$ 0.3

XML

DISCONTINUED OPERATIONS

3 Months Ended

Mar. 31, 2013

DISCONTINUED OPERATIONS

DISCONTINUED OPERATIONS

NOTE 5 — DISCONTINUED OPERATIONS

Discontinued Operations at Holding Company and Other Segment

During the three months ended March 31, 2013, and 2012, we recorded $6.0 million and $1.9 million of after-tax gains, respectively, in discontinued operations at the holding company and other segment. 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.

Discontinued Operations at Integrys Energy Services Segment

Potential Sale of Combined Locks Energy Center

Integrys Energy Services is currently pursuing the sale of the Combined Locks Energy Center (Combined Locks), a natural gas-fired co-generation facility located in Wisconsin, as part of its long-term energy asset strategy. The sale of Combined Locks is expected to be completed by the end of 2013.

The carrying values of the major classes of assets related to Combined Locks classified as held for sale on the balance sheets were as follows:

(Millions)	March 31, 2013		December 31, 2012
Inventories	$	0.5	$	0.5
Property, plant, and equipment, net of accumulated depreciation of $0.5 million	2.0		2.0
Total assets	$	2.5	$	2.5

A summary of the components of discontinued operations related to Combined Locks recorded on the income statements was as follows at March 31:

(Millions)	2013			2012
Nonregulated revenues	$	—		$	0.4
Nonregulated cost of sales	(0.1		)	(0.3		)
Operating and maintenance expense	(0.1		)	(0.2		)
Depreciation and amortization expense	—			(0.1		)
Taxes other than income taxes	—			(0.1		)
Loss before taxes	(0.2		)	(0.3		)
Benefit for income taxes	0.1			0.1
Discontinued operations, net of tax	$	(0.1	)	$	(0.2	)

Sale of WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC

In March 2013, WPS Empire State, Inc, a subsidiary of Integrys Energy Services, sold all of the membership interests of WPS Beaver Falls Generation, LLC (Beaver Falls) and WPS Syracuse Generation, LLC (Syracuse), both of which own natural gas-fired generation plants located in the state of New York. The cash proceeds from the sale were $1.6 million, subject to certain post-closing adjustments primarily related to working capital. The sale agreement also includes a potential annual payment to Integrys Energy Services for a four-year period following the sale based on a certain level of earnings achieved by the buyer (an earn-out).

The carrying values of the major classes of assets and liabilities related to Beaver Falls and Syracuse classified as held for sale on the balance sheets were as follows:

(Millions)	As of the Closing Date on March 14, 2013		As of December 31, 2012
Inventories	$	1.8	$	1.8
Other current assets	0.2		—
Property, plant, and equipment	5.7		5.7
Other long-term assets	0.1		0.1
Total assets	$	7.8	$	7.6
Total liabilities – other current liabilities	$	0.4	$	0.2

In conjunction with the sale, the buyer will assume certain derivative contracts with Integrys Energy Services. The derivative contracts establish physical capacity hedges for the retail electric business and physical hedges associated with the sale of capacity to external counterparties. Integrys Energy Services is in the process of novating the external capacity sales contracts to the buyer, upon which time the corresponding purchase transactions with the buyer will terminate. The carrying value of the derivative contract liabilities assumed by the buyer were $6.8 million at March 31, 2013.

A summary of the components of discontinued operations related to Beaver Falls and Syracuse recorded on the income statements were as follows at March 31:

(Millions)	2013			2012
Nonregulated revenues	$	1.2		$	(0.7	)
Nonregulated cost of sales	(0.9		)	(0.4		)
Operating and maintenance expense *	0.4			(0.5		)
Depreciation and amortization expense	—			(0.2		)
Taxes other than income taxes	(0.3		)	(0.8		)
Income (loss) before taxes	0.4			(2.6		)
(Provision) benefit for income taxes	(0.2		)	1.0
Discontinued operations, net of tax	$	0.2		$	(1.6	)

* Includes a $1.0 million gain on sale at closing.

The sale of Beaver Falls and Syracuse will generate immaterial cash flows from providing certain administrative transition services to the buyer for up to a six-month period following the sale and from the potential four-year annual earn-out payment. Integrys Energy Services will also continue to purchase capacity from these facilities to satisfy certain capacity obligations, until novated to the buyer, and settle certain forward financial natural gas swaps under contracts that existed at the time of sale. Both of these transactions will generate cash flows that will expire upon novation or within two years of the sale and are not considered significant to the overall operations of Beaver Falls and Syracuse. Integrys Energy Services does not have the ability to significantly influence the operating or financial policies of Beaver Falls and Syracuse and also does not have significant continuing involvement in the operations of Beaver Falls and Syracuse. Therefore, the continuing cash flows discussed above are not considered direct cash flows of Beaver Falls and Syracuse.

Sale of WPS Westwood Generation, LLC

In November 2012, Sunbury Holdings, LLC, a subsidiary of Integrys Energy Services, sold all of the membership interests of WPS Westwood Generation, LLC (Westwood), a waste coal generation plant located in Pennsylvania. The cash proceeds related to the sale were $2.6 million. Integrys Energy Services also received a $4.0 million note receivable from the buyer with a seven and one-half year term.

A summary of the components of discontinued operations related to Westwood recorded on the income statements were as follows at March 31:

(Millions)	2012
Nonregulated revenues	$	4.1
Nonregulated cost of sales	(1.3		)
Operating and maintenance expense	(1.0		)
Depreciation and amortization expense	(0.3		)
Taxes other than income taxes	(0.1		)
Interest expense	(0.1		)
Income before taxes	1.3
Provision for income taxes	(0.5		)
Discontinued operations, net of tax	$	0.8

Integrys Energy Services will receive interest income for seven and one-half years from the sale date related to the note receivable from the buyer. The sale will also generate immaterial cash flows from providing certain administrative transition services to the buyer for up to a six-month period following the sale. However, Integrys Energy Services does not have the ability to significantly influence the operating or financial policies of Westwood and also does not have significant continuing involvement in the operations of Westwood. Therefore, the continuing cash flows discussed above are not considered direct cash flows of Westwood.

XML

ACQUISITIONS

3 Months Ended

Mar. 31, 2013

ACQUISITIONS

ACQUISITIONS

NOTE 4 — ACQUISITIONS

Acquisition of Fox Energy Center

In March 2013, WPS acquired all of the equity interests in Fox Energy Company LLC for $391.6 million, subject to post-closing working capital adjustments. Fox Energy Company LLC was dissolved into WPS immediately after the purchase.

The purchase included the Fox Energy Center, a 593-megawatt combined-cycle electric generating facility located in Wisconsin, along with associated contracts. Fox Energy Center is a dual-fuel facility, equipped to use fuel oil, but expected to run primarily on natural gas. This plant gives WPS a more balanced mix of owned electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources. In giving its approval for the purchase, the PSCW stated that the purchase price was reasonable and will benefit ratepayers.

The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:

(Millions)
Assets acquired
Inventories	$	3.0
Other current assets	0.6
Property, plant, and equipment	374.4
Other long-term assets *	15.6
Total assets acquired	$	393.6
Liabilities assumed
Accounts payable	$	2.0
Total liabilities assumed	$	2.0

* Relates to intangible assets recorded for contractual services agreements. See Note 8, "Goodwill and Other Intangible Assets," for more information.

Prior to the purchase, WPS supplied natural gas for the facility and purchased 500 megawatts of capacity and the associated energy output under a tolling arrangement. WPS paid $50.0 million for the early termination of the tolling arrangement. This amount was recorded as a regulatory asset, as WPS is authorized recovery by the PSCW.

The purchase was financed with a combination of short-term debt and cash flow from operations. The short-term debt will be replaced later in 2013 with long-term financing.

WPS received regulatory approval to defer incremental costs associated with the purchase of the facility. Operating costs for the Fox Energy Center subsequent to the date of acquisition are included in our income statement. Due to regulatory deferral, these costs had no impact on net income. Pro forma adjustments to our revenues and earnings prior to the date of acquisition would not be meaningful or material. Prior to the acquisition, the Fox Energy Center was a nonregulated plant and sold all of its output to third parties, with most of the output purchased by WPS. The plant is now part of WPS's regulated fleet, used to serve its customers.

Acquisition of Compass Energy Services

In May 2013, Integrys Energy Services acquired all of the equity interests of Compass Energy Services, Inc. and its wholly-owned subsidiary (“Compass”), a nonregulated retail natural gas business supplying commercial and industrial customers primarily in the Mid Atlantic and Ohio regions. This transaction will expand Integrys Energy Services' retail natural gas presence in these markets and provide a solid foundation for future growth in these regions.

This acquisition is not material to us. Integrys Energy Services made an initial cash payment of $12.0 million upon closing, and under the terms of the purchase agreement, the former owners of Compass will be eligible to receive additional cash consideration of up to $8.0 million (but no less than $3.0 million), based upon the financial performance of Compass over the next five years. Due to the timing of this acquisition, certain disclosures, including the allocation of the purchase price, have been omitted because the initial accounting for the business combination was incomplete as of the filing date.

XML

COMMON EQUITY

3 Months Ended

Mar. 31, 2013

COMMON EQUITY

COMMON EQUITY

NOTE 16 — COMMON EQUITY

We had the following changes to issued common stock during the three months ended March 31, 2013:

Common stock at December 31, 2012	78,287,906
Shares issued
Stock Investment Plan	114,365
Stock-based compensation	317,677
Rabbi trust shares	90,000
Common stock at March 31, 2013	78,809,948

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 02/05/2013	Issuing new shares *
01/01/2012 – 02/04/2013	Purchased shares on the open market

^* These stock issuances increased equity $22.3 million in 2013.

The following table reconciles common shares issued and outstanding:

	March 31, 2013			December 31, 2012
	Shares	Average Cost *		Shares	Average Cost *
Common stock issued	78,809,948			78,287,906
Less:
Deferred compensation rabbi trust	456,852	$	48.23	385,439	$	46.03
Total common shares outstanding	78,353,096			77,902,467

* Based on our stock price on the day the shares entered the deferred compensation rabbi trust. Shares paid out of the trust are valued at the average cost of shares in the trust.

Earnings Per Share

Basic earnings per share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for shares we are obligated to issue under the deferred compensation and restricted share unit plans. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include in-the-money stock options, performance stock rights, restricted share units, and certain shares issuable under the deferred compensation plan. The calculations of diluted earnings per share for the three months ended March 31, 2013, and 2012, excluded 0.2 million and 0.8 million, respectively, out-of-the-money stock options that had an anti-dilutive effect. The following table reconciles our computation of basic and diluted earnings per share:

	Three Months Ended March 31
(Millions, except per share amounts)	2013			2012
Numerator:
Net income from continuing operations	$	182.2		$	98.8
Discontinued operations, net of tax	6.1			0.9
Preferred stock dividends of subsidiary	(0.8		)	(0.8		)
Net income attributed to common shareholders	$	187.5		$	98.9
Denominator:
Average shares of common stock — basic	78.7			78.6
Effect of dilutive securities
Stock-based compensation	0.4			0.4
Deferred compensation	0.2			0.2
Average shares of common stock — diluted	79.3			79.2
Earnings per common share
Basic	$	2.38		$	1.26
Diluted	2.37			1.25

Dividend Restrictions

Our ability as a holding company to pay dividends is largely dependent upon the availability of funds from our subsidiaries. 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.

The PSCW allows WPS to pay dividends on its common stock of no more than 103% of the previous year’s common stock dividend. WPS may return capital to us if its average financial common equity ratio is at least 51% on a calendar-year basis. WPS must obtain PSCW approval if a return of capital would cause its average financial common equity ratio to fall below this level. Our right to receive dividends on the common stock of WPS is also subject to the prior rights of WPS’s preferred shareholders and to provisions in WPS’s restated articles of incorporation, which limit the amount of common stock dividends that WPS may pay if its common stock and common stock surplus accounts constitute less than 25% of its total capitalization.

NSG’s long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock.

PGL and WPS have short-term debt obligations containing financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of their outstanding debt obligations.

We also have short-term and long-term debt obligations that contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of outstanding debt obligations. At March 31, 2013, these covenants did not restrict the payment of any dividends beyond the amount restricted under our subsidiary requirements described above.

As of March 31, 2013, total restricted net assets were $1,676.0 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $129.4 million at March 31, 2013.

We have the option to defer interest payments on our outstanding Junior Subordinated Notes, from time to time, for one or more periods of up to ten consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, purchase, acquire, or make a liquidation payment on, any of our capital stock.

Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.

Capital Transactions with Subsidiaries

During the three months ended March 31, 2013, capital transactions with subsidiaries were as follows (in millions):

Subsidiary	Dividends To Parent		Return Of  Capital To Parent		Equity Contributions From Parent
ITF (1)	$	—	$	—	$	11.7
MERC	—		21.0		—
WPS	27.1		—		200.0
WPS Investments, LLC (2)	17.3		—		1.7
Total	$	44.4	$	21.0	$	213.4

⁽¹⁾  ITF is a direct wholly owned subsidiary of PELLC. As a result, it makes distributions to PELLC, and receives equity contributions from PELLC. Subject to applicable law, PELLC does not have any dividend restrictions or limitations on distributions to us.

⁽²⁾  WPS Investments, LLC is a consolidated subsidiary that is jointly owned by us, WPS, and UPPCO. At March 31, 2013, we had an 85.86% ownership interest, while WPS and UPPCO had an 11.66% and 2.48% ownership interest, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2013, all equity contributions to WPS Investments, LLC were made solely by us.

XML

COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2013

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

NOTE 12 — COMMITMENTS AND CONTINGENCIES

(a) Unconditional Purchase Obligations and Purchase Order Commitments

We and our subsidiaries routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. The regulated natural gas utilities have obligations to distribute and sell natural gas to their customers, and the regulated electric utilities have obligations to distribute and sell electricity to their customers. The utilities expect to recover costs related to these obligations in future customer rates. Additionally, the majority of the energy supply contracts entered into by Integrys Energy Services are to meet its obligations to deliver energy to customers. The following table shows our minimum future commitments related to these purchase obligations as of March 31, 2013, including those of our subsidiaries.

				Payments Due By Period
(Millions)	Date Contracts Extend Through	Total Amounts Committed		2013		2014		2015		2016		2017		Later Years
Natural gas utility supply and transportation	2028	$	823.2	$	124.9	$	156.3	$	137.9	$	125.7	$	86.9	$	191.5
Electric utility
Purchased power	2029	852.6		121.3		37.7		33.0		29.4		28.4		602.8
Coal supply and transportation	2017	122.7		44.4		41.2		30.4		6.2		0.5		—
Nonregulated electricity and natural gas supply	2020	830.6		479.8		305.9		34.3		4.6		1.3		4.7
Total		$	2,629.1	$	770.4	$	541.1	$	235.6	$	165.9	$	117.1	$	799.0

We and our subsidiaries also had commitments of $713.5 million in the form of purchase orders issued to various vendors at March 31, 2013, that relate to normal business operations, including construction projects.

(b) Environmental Matters

Air Permitting Violation Claims

Weston and Pulliam Clean Air Act (CAA) Issues:

In November 2009, the EPA issued a Notice of Violation (NOV) to WPS alleging violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. WPS reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree, which was filed in the U.S. District Court (Court) in January 2013. This Consent Decree was approved by the Court in March 2013, after a public comment period. The final Consent Decree includes:

• the installation of emission control technology, including ReACT™ or an approved alternative, on Weston 3,

• changed operating conditions (including refueling, repowering, and/or retirement of units),

• limitations on plant emissions,

• beneficial environmental projects totaling $6.0 million (various options, including capital projects, are available), and

• a civil penalty of $1.2 million.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. As of March 31, 2013, no decision had been made on how to address this requirement. Therefore, retirement of the Weston and Pulliam units mentioned in the Consent Decree was not considered probable.

We believe that significant costs prudently incurred as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty, will be recoverable from customers.

In May 2010, WPS received from the Sierra Club a Notice of Intent (NOI) to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of March 31, 2013. It is unknown whether the Sierra Club will take further action in the future.

Columbia and Edgewater CAA Issues:

In December 2009, the EPA issued an NOV to Wisconsin Power and Light (WP&L), the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric and WPS. The NOV alleges violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, WP&L, and Madison Gas and Electric (Joint Owners) reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree, which was filed in the Court on April 22, 2013. The Consent Decree includes:

• the installation of emission control technology, including the installation of scrubbers at the Columbia plant,

• changed operating conditions (including refueling, repowering, and/or retirement of units),

• limitations on plant emissions,

• beneficial environmental projects, with WPS's portion totaling $1.3 million (various options, including capital projects, are available), and

• WPS's portion of a civil penalty and legal fees totaling $0.4 million.

The public comment period will end on May 28, 2013. The final terms of the Consent Decree may be different than currently anticipated.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain of the Columbia and Edgewater units. As of March 31, 2013, no decision had been made on how to address this requirement. Therefore, retirement of the Colombia and Edgewater units mentioned in the Consent Decree was not considered probable.

We believe that significant costs prudently incurred as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty, will be recoverable from customers.

In September 2010, the Sierra Club filed a lawsuit against WP&L, which included allegations that modifications made at the Edgewater plant did not comply with the CAA. A similar case had also been filed by the Sierra Club related to the Columbia plant, which was dismissed without prejudice due to the impending settlement and Consent Decree. As part of the Consent Decree settlement, the Sierra Club filed a new suit related to the Columbia plant, which gave notice of the filing of the Consent Decree. It is anticipated that the Sierra Club will dismiss both suits against WP&L once the Consent Decree is approved by the Court.

Weston Title V Air Permit:

In November 2010, the WDNR provided a draft revised permit for the Weston 4 plant. WPS objected to proposed changes in mercury limits and requirements on the boilers as beyond the authority of the WDNR and met with the WDNR to resolve these issues. In September 2011, the WDNR issued an updated draft revised permit and a request for public comments. Due to the significance of the changes to the draft revised permit, the WDNR re-issued the draft revised permit for additional comments in February 2013. In July 2012, Clean Wisconsin filed suit against the WDNR alleging failure to issue or delay in issuing the Weston Title V permit. WPS and the WDNR both filed motions to dismiss Clean Wisconsin's lawsuit, which the Court granted in February 2013. Clean Wisconsin appealed this decision, but briefs have not yet been filed in the appeal. We do not expect this matter to have a material impact on our financial statements.

Pulliam Title V Air Permit:

The WDNR issued a renewal of the permit for the Pulliam plant in April 2009. In June 2010, the EPA issued an order directing the WDNR to respond to comments raised by the Sierra Club in its June 2009 petition requesting the EPA to object to the permit.

In April 2011, WPS received notification that the Sierra Club filed a civil lawsuit against the EPA based on what the Sierra Club alleged to be an unreasonable delay in responding to the June 2010 order. WPS is not a party to this litigation, but intervened to protect its interests. In February 2012, the WDNR sent a proposed permit and response to the EPA for a 45-day review, which allowed the parties to enter into a settlement agreement that has been approved by the Court.

In May 2012, the Sierra Club filed another petition requesting that the EPA again object to the proposed permit and response, which the EPA denied in January 2013. The Sierra Club did not appeal the EPA decision. The Sierra Club also recently filed a request for a contested case proceeding regarding the permit, which was granted in part by the WDNR. A schedule has not yet been set for the contested case proceeding.

We are reviewing all of these matters, but we do not expect them to have a material impact on our financial statements.

Columbia Title V Air Permit:

In February 2011, the Sierra Club filed a lawsuit against the EPA seeking to have the EPA take over the Title V permit process for the Columbia plant. The Sierra Club alleges the EPA must now act on the reconsideration of the Title V permit since the WDNR has exceeded its time frame in which to respond to an EPA order issued in 2009. In May 2011, the WDNR issued a revised draft Title V permit in response to the EPA's order.

In June 2012, WP&L received notice from the EPA of the EPA's proposal for WP&L to apply for a federally-issued Title V permit since the WDNR has not addressed the EPA's objections to the Title V permit issued for the Columbia plant. A hearing has been set for June 3, 2013. If the EPA decides to require the submittal of an operation permit application, it would be due within six months of the EPA's notice to WP&L. WP&L believes the previously issued Title V permit for the Columbia plant is still valid.

We do not expect this matter to have a material impact on our financial statements.

WDNR Issued NOVs:

Since 2008, WPS has received four NOVs from the WDNR alleging various violations of the different air permits for the entire Weston plant and Weston 1, Weston 2, and Weston 4 individually. WPS also received an NOV for a clerical error involving pages missing from a quarterly report for Weston. Corrective actions have been taken for the events in the five NOVs. In December 2011, the WDNR referred several of the claims in the NOVs to the state Justice Department for enforcement. WPS began discussing the pending NOVs and their resolution with the Justice Department in late 2012. We do not expect this matter to have a material impact on our financial statements.

Weston 4 Construction Permit

From 2004 to 2009, the Sierra Club filed various petitions objecting to the construction permit issued for the Weston 4 plant. In June 2010, the Wisconsin Court of Appeals affirmed the Weston 4 construction permit, but directed the WDNR to reopen the permit to set specific visible emissions limits. In July 2010, WPS, the WDNR, and the Sierra Club filed Petitions for Review with the Wisconsin Supreme Court. In March 2011, the Wisconsin Supreme Court denied all Petitions for Review. Other than the specific visible emissions limits issue, all other challenges to the construction permit are now resolved. WPS is working with the WDNR to resolve this issue as part of the current construction permit renewal process. We do not expect this matter to have a material impact on our financial statements.

Mercury and Interstate Air Quality Rules

Mercury:

The State of Wisconsin's mercury rule requires a 40% reduction from historical baseline mercury emissions, beginning January 1, 2010, through the end of 2014. Beginning in 2015, electric generating units above 150 megawatts will be required to reduce mercury emissions by 90% from the historical baseline. Reductions can be phased in and the 90% target delayed until 2021 if additional sulfur dioxide and nitrogen oxide reductions are implemented. By 2015, electric generating units above 25 megawatts, but less than 150 megawatts, must reduce their mercury emissions to a level defined by the Best Available Control Technology rule. As of March 31, 2013, WPS estimates capital costs of approximately $8 million for its wholly owned plants to achieve the required reductions. The capital costs are expected to be recovered in future rates.

In December 2011, the EPA issued the final Utility Mercury and Air Toxics Standards (MATS), which will regulate emissions of mercury and other hazardous air pollutants beginning in 2015. The State of Wisconsin is assessing how its current mercury rule will be impacted by the MATS rule. We are currently evaluating options for achieving the emission limits specified in this rule, but we do not anticipate the cost of compliance to be significant. We expect to recover future compliance costs in future rates.

Sulfur Dioxide and Nitrogen Oxide:

In July 2011, the EPA issued a final rule known as the Cross State Air Pollution Rule (CSAPR), which numerous parties, including WPS, challenged in the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). The new rule was to become effective January 1, 2012. However, in December 2011, the CSAPR requirements were stayed by the D.C. Circuit and a previous rule, the Clean Air Interstate Rule (CAIR), was implemented during the stay period. In August 2012, the D.C. Circuit issued their ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. In October 2012, the EPA and several other parties filed petitions for a rehearing of the D.C. Circuit's decision, which the D.C. Circuit denied in January 2013.

Under CAIR, units affected by the Best Available Retrofit Technology (BART) rule were considered in compliance with BART for sulfur dioxide and nitrogen oxide emissions if they were in compliance with CAIR. This determination was updated when CSAPR was issued (CSAPR satisfied BART), and the EPA has not revised it to reflect the reinstatement of CAIR. Although particulate emissions also contribute to visibility impairment, the WDNR's modeling has shown the impairment to be so insignificant that additional capital expenditures on controls are not warranted.

Due to the uncertainty surrounding this rulemaking, we are currently unable to predict whether WPS will have to purchase additional emission allowances, idle or abandon certain units, or change how certain units are operated. WPS expects to recover any future compliance costs in future rates. The potential impact on Integrys Energy Services is not expected to be material.

Manufactured Gas Plant Remediation

Our natural gas utilities, their predecessors, and certain former affiliates operated facilities in the past at multiple sites for the purpose of manufacturing and storing manufactured gas. In connection with these activities, waste materials were produced that may have resulted in soil and groundwater contamination at these sites. Under certain laws and regulations relating to the protection of the environment, our natural gas utilities are required to undertake remedial action with respect to some of these materials. They are coordinating the investigation and cleanup of the sites subject to EPA jurisdiction under what is called a "multi-site" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies.

Our natural gas utilities are responsible for the environmental remediation of 53 sites, of which 20 have been transferred to the EPA Superfund Alternative Sites Program. Under the EPA's program, the remedy decisions at these sites will be made using risk-based criteria typically used at Superfund sites. As of March 31, 2013, we estimated and accrued for $639.6 million of future undiscounted investigation and cleanup costs for all sites. We may adjust these estimates in the future due to remedial technology, regulatory requirements, remedy determinations, and any claims of natural resource damages. As of March 31, 2013, cash expenditures for environmental remediation not yet recovered in rates were $30.0 million. We recorded a regulatory asset of $669.6 million at March 31, 2013, which is net of insurance recoveries received of $63.1 million, related to the expected recovery through rates of both cash expenditures and estimated future expenditures.

Management believes that any costs incurred for environmental activities relating to former manufactured gas plant operations that are not recoverable through contributions from other entities or from insurance carriers have been prudently incurred and are, therefore, recoverable through rates for MGU, NSG, PGL, and WPS. Accordingly, we do not expect these costs to have a material impact on our financial statements. However, any changes in the approved rate mechanisms for recovery of these costs, or any adverse conclusions by the various regulatory commissions with respect to the prudence of costs actually incurred, could materially affect recovery of such costs through rates.

XML

ADVERTISING COSTS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
ADVERTISING COSTS
Capitalized direct-response advertising costs, net of accumulated amortization	$ 4.1		$ 5.5
Impairment related to capitalized direct-response advertising cost	0	0
Period of amortization of direct-response advertising costs over estimated period of benefit	2 years
Amortization of direct-response advertising costs	3.0	1.0
Other advertising expense	$ 2.3	$ 1.7

XML

GOODWILL AND OTHER INTANGIBLE ASSETS

3 Months Ended

Mar. 31, 2013

GOODWILL AND OTHER INTANGIBLE ASSETS

GOODWILL AND OTHER INTANGIBLE ASSETS

NOTE 8 — GOODWILL AND OTHER INTANGIBLE ASSETS

We had no material changes to the carrying amount of goodwill during the three months ended March 31, 2013, and 2012.

In connection with the acquisition of Fox Energy Company LLC, WPS recorded $15.6 million of intangible assets in the first quarter of 2013. The intangible assets relate to contractual service agreements, which provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The approximate amortization period of these intangible assets is 7 years.

The identifiable intangible assets other than goodwill listed below are part of other long-term assets on the balance sheets. An insignificant amount was recorded as assets held for sale on the balance sheets.

	March 31, 2013							December 31, 2012
(Millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets
Customer-related (1)	$	22.4	$	(15.0	)	$	7.4	$	22.4	$	(14.7	)	$	7.7
Contractual service agreements (2)	15.6		—			15.6		—		—			—
Patents/intellectual property (3)	7.2		(0.3		)	6.9		7.2		(0.3		)	6.9
Compressed natural gas fueling contract assets (4)	5.6		(1.7		)	3.9		5.6		(1.3		)	4.3
Renewable energy credits (5)	5.1		—			5.1		3.1		—			3.1
Nonregulated easements (6)	3.8		(1.0		)	2.8		3.8		(0.9		)	2.9
Customer-owned equipment modifications (7)	4.0		(0.6		)	3.4		4.0		(0.5		)	3.5
Other	0.5		(0.3		)	0.2		0.5		(0.2		)	0.3
Total	$	64.2	$	(18.9	)	$	45.3	$	46.6	$	(17.9	)	$	28.7
Unamortized intangible assets
MGU trade name	$	5.2	$	—		$	5.2	$	5.2	$	—		$	5.2
Trillium trade name	3.5		—			3.5		3.5		—			3.5
Pinnacle trade name	1.5		—			1.5		1.5		—			1.5
Total intangible assets	$	74.4	$	(18.9	)	$	55.5	$	56.8	$	(17.9	)	$	38.9

⁽¹⁾  Represents customer relationship assets associated with PELLC’s former nonregulated retail natural gas and electric operations and Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) compressed natural gas fueling operations. The remaining weighted-average amortization period for customer-related intangible assets at March 31, 2013, was approximately 9 years.

⁽²⁾  Represents contractual service agreements related to maintenance on the combustion turbine generators at the Fox Energy Center. The remaining amortization period for these intangible assets at March 31, 2013, was approximately 7 years.

⁽³⁾  Represents the fair value of patents/intellectual property at Pinnacle related to a system for more efficiently compressing natural gas to allow for faster fueling. The remaining amortization period at March 31, 2013, was approximately 9 years.

⁽⁴⁾  Represents the fair value of Trillium and Pinnacle contracts acquired in September 2011. The remaining amortization period at March 31, 2013, was approximately 8 years.

⁽⁵⁾  Used at Integrys Energy Services to comply with state Renewable Portfolio Standards and to support customer commitments.

⁽⁶⁾  Relates to easements supporting a pipeline at Integrys Energy Services. The easements are amortized on a straight-line basis, with a remaining amortization period at March 31, 2013, of approximately 11 years.

⁽⁷⁾  Relates to modifications made by Integrys Energy Services and Trillium to customer-owned equipment. These intangible assets are amortized on a straight-line basis, with a remaining weighted-average amortization period at March 31, 2013, of approximately 11 years.

Amortization expense recorded as a component of nonregulated cost of sales in the statements of income for the three months ended March 31, 2013, and 2012, was $0.4 million and $1.6 million, respectively.

Amortization expense recorded as a component of depreciation and amortization expense in the statements of income for the three months ended March 31, 2013, and 2012, was $0.5 million and $0.7 million, respectively.

An insignificant amount of amortization expense was recorded in discontinued operations for the three months ended March 31, 2013, and 2012.

Amortization expense for the next five fiscal years is estimated to be:

	For the Year Ending December 31
(Millions)	2013		2014		2015		2016		2017
Amortization to be recorded in nonregulated cost of sales	$	6.7	$	1.2	$	1.1	$	0.9	$	0.9
Amortization to be recorded in depreciation and amortization expense	3.8		4.1		4.1		3.9		3.8

XML

GOODWILL AND OTHER INTANGIBLE ASSETS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
GOODWILL AND OTHER INTANGIBLE ASSETS
Changes in the carrying amount of goodwill	$ 0	$ 0
Amortized intangible assets
Amortized intangible assets, carrying amount, gross	64.2		46.6
Accumulated amortization of intangible assets	(18.9)		(17.9)
Amortized intangible assets, net	45.3		28.7
Unamortized intangible assets
Total intangible assets, gross	74.4		56.8
Total intangible assets	55.5		38.9
Nonregulated cost of sales
Amortized intangible assets
Amortization expense	0.4	1.6
Amortization expense for the next five fiscal years
Amortization expense, 2013	6.7
Amortization expense, 2014	1.2
Amortization expense, 2015	1.1
Amortization expense, 2016	0.9
Amortization expense, 2017	0.9
Depreciation and amortization
Amortized intangible assets
Amortization expense	0.5	0.7
Amortization expense for the next five fiscal years
Amortization expense, 2013	3.8
Amortization expense, 2014	4.1
Amortization expense, 2015	4.1
Amortization expense, 2016	3.9
Amortization expense, 2017	3.8
Customer-related
Amortized intangible assets
Amortized intangible assets, carrying amount, gross	22.4		22.4
Accumulated amortization of intangible assets	(15.0)		(14.7)
Amortized intangible assets, net	7.4		7.7
Amortization period	P9Y
Contractual service agreements
Amortized intangible assets
Amortized intangible assets, carrying amount, gross	15.6
Amortized intangible assets, net	15.6
Amortization period	P7Y
Contractual service agreements | Fox Energy Company, LLC | WPS
Amortized intangible assets
Amortized intangible assets, carrying amount, gross	15.6
Amortization period	P7Y
Patents/intellectual property
Amortized intangible assets
Amortized intangible assets, carrying amount, gross	7.2		7.2
Accumulated amortization of intangible assets	(0.3)		(0.3)
Amortized intangible assets, net	6.9		6.9
Amortization period	P9Y
Compressed natural gas fueling contract assets
Amortized intangible assets
Amortized intangible assets, carrying amount, gross	5.6		5.6
Accumulated amortization of intangible assets	(1.7)		(1.3)
Amortized intangible assets, net	3.9		4.3
Amortization period	P8Y
Renewable energy credits
Amortized intangible assets
Amortized intangible assets, carrying amount, gross	5.1		3.1
Amortized intangible assets, net	5.1		3.1
Nonregulated easements
Amortized intangible assets
Amortized intangible assets, carrying amount, gross	3.8		3.8
Accumulated amortization of intangible assets	(1.0)		(0.9)
Amortized intangible assets, net	2.8		2.9
Amortization period	P11Y
Customer-owned equipment modifications
Amortized intangible assets
Amortized intangible assets, carrying amount, gross	4.0		4.0
Accumulated amortization of intangible assets	(0.6)		(0.5)
Amortized intangible assets, net	3.4		3.5
Amortization period	P11Y
Other amortized intangible assets
Amortized intangible assets
Amortized intangible assets, carrying amount, gross	0.5		0.5
Accumulated amortization of intangible assets	(0.3)		(0.2)
Amortized intangible assets, net	0.2		0.3
Trade name | MGU
Unamortized intangible assets
Unamortized intangible asset, carrying amount	5.2		5.2
Trade name | Trillium
Unamortized intangible assets
Unamortized intangible asset, carrying amount	3.5		3.5
Trade name | Pinnacle CNG Systems
Unamortized intangible assets
Unamortized intangible asset, carrying amount	$ 1.5		$ 1.5

XML

INVESTMENT IN ATC

3 Months Ended

Mar. 31, 2013

INVESTMENT IN ATC

INVESTMENT IN ATC

NOTE 6 — INVESTMENT IN ATC

Our electric transmission investment segment consists of WPS Investments LLC’s ownership interest in ATC, which was approximately 34% at March 31, 2013. ATC is a for-profit, transmission-only company regulated by FERC.

The following table shows changes to our investment in ATC.

	Three Months Ended March 31
(Millions)	2013		2012
Balance at the beginning of period	$	476.6	$	439.4
Add: Earnings from equity method investment	21.7		20.8
Add: Capital contributions	1.7		3.4
Less: Dividends received	17.3		16.7
Balance at the end of period	$	482.7	$	446.9

Financial data for all of ATC is included in the following tables:

	Three Months Ended March 31
(Millions)	2013		2012
Income statement data
Revenues	$	151.8	$	147.7
Operating expenses	69.8		69.6
Other expense	21.5		20.0
Net income	$	60.5	$	58.1

(Millions)	March 31, 2013		December 31, 2012
Balance sheet data
Current assets	$	69.3	$	63.1
Noncurrent assets	3,325.3		3,274.7
Total assets	$	3,394.6	$	3,337.8
Current liabilities	$	261.5	$	251.5
Long-term debt	1,550.0		1,550.0
Other noncurrent liabilities	124.8		95.8
Shareholders’ equity	1,458.3		1,440.5
Total liabilities and shareholders’ equity	$	3,394.6	$	3,337.8

XML

INVENTORIES

3 Months Ended

Mar. 31, 2013

INVENTORIES

INVENTORIES

NOTE 7 — INVENTORIES

PGL and NSG price natural gas storage injections at the calendar year average of the cost of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At March 31, 2013, we had a temporary LIFO liquidation credit of $83.2 million recorded within other current liabilities on our balance sheet. Due to seasonality requirements, PGL and NSG expect interim reductions in LIFO layers to be replenished by year end.

XML

SHORT-TERM DEBT AND LINES OF CREDIT

3 Months Ended

Mar. 31, 2013

SHORT-TERM DEBT AND LINES OF CREDIT

SHORT-TERM DEBT AND LINES OF CREDIT

NOTE 9 — SHORT-TERM DEBT AND LINES OF CREDIT

Our outstanding short-term borrowings were as follows:

(Millions, except percentages)	March 31, 2013		December 31, 2012
Commercial paper	$	556.4	$	482.4
Average discount rate on commercial paper	0.33%		0.40%
Loan under term credit facility *	$	200.0	—
Average interest rate on loan under term credit facility	0.80%		—

* Relates to the purchase of Fox Energy Company LLC. See Note 4, "Acquisitions," for more information regarding this purchase.

The commercial paper outstanding at March 31, 2013, had maturity dates ranging from April 1, 2013, through May 24, 2013. The terms of the loan outstanding under the term credit facility require repayment upon the earlier of issuance of replacement long-term debt or December 31, 2013.

The table below presents our average amount of short-term borrowings based on daily outstanding balances during the three months ended March 31:

(Millions)	2013		2012
Average amount of commercial paper	$	400.7	$	357.5
Average amount of loan under term credit facility	8.9		—

We manage our liquidity by maintaining adequate external financing commitments. The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities, and our short-term debt:

(Millions)	Maturity	March 31, 2013		December 31, 2012
Revolving credit facility (Integrys Energy Group)	05/17/2014	$	275.0	$	275.0
Revolving credit facility (Integrys Energy Group)	05/17/2016	200.0		200.0
Revolving credit facility (Integrys Energy Group)	06/13/2017	635.0		635.0
Revolving credit facility (WPS)	05/17/2014	135.0		135.0
Revolving credit facility (WPS)	06/13/2017	115.0		115.0
Revolving credit facility (PGL)	06/13/2017	250.0		250.0
Term credit facility (WPS) *	12/31/2013	200.0		—
Total short-term credit capacity		$	1,810.0	$	1,610.0
Less:
Letters of credit issued inside credit facilities		$	29.1	$	25.5
Loan outstanding under term credit facility *		200.0		—
Commercial paper outstanding		556.4		482.4
Accrued interest or original discount on outstanding commercial paper		0.1		—
Available capacity under existing agreements		$	1,024.4	$	1,102.1

* Relates to the purchase of Fox Energy Company LLC. See Note 4, "Acquisitions," for more information regarding this purchase.

XML

INCOME TAXES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
INCOME TAXES
Effective Tax Rate (as a percent)	37.60%	32.40%
Federal statutory tax rate (as a percent)	35.00%	35.00%
Decreased liability for unrecognized tax benefits	$ 6.8

XML

REGULATORY ENVIRONMENT (Details) (USD $) In Millions, unless otherwise specified				12 Months Ended							12 Months Ended	3 Months Ended																			0 Months Ended	1 Months Ended	16 Months Ended		1 Months Ended
	Mar. 29, 2013 Public Service Commission of Wisconsin (PSCW) 2014 Rates Entity's Original Request WPS	Mar. 29, 2013 Public Service Commission of Wisconsin (PSCW) 2014 Rates Retail Electric Rate Case Entity's Original Request WPS	Mar. 29, 2013 Public Service Commission of Wisconsin (PSCW) 2014 Rates Natural Gas Rate Case Entity's Original Request WPS	Dec. 31, 2012 Public Service Commission of Wisconsin (PSCW) 2013 Rates Settlement agreement WPS	Dec. 06, 2012 Public Service Commission of Wisconsin (PSCW) 2013 Rates Settlement agreement WPS	Mar. 31, 2013 Public Service Commission of Wisconsin (PSCW) 2013 Rates Retail Electric Rate Case Settlement agreement WPS	Dec. 06, 2012 Public Service Commission of Wisconsin (PSCW) 2013 Rates Retail Electric Rate Case Settlement agreement WPS	Dec. 06, 2012 Public Service Commission of Wisconsin (PSCW) 2013 Rates Natural Gas Rate Case Settlement agreement WPS	Dec. 09, 2011 Public Service Commission of Wisconsin (PSCW) 2012 Rates Retail Electric Rate Case Rate Order WPS	Dec. 09, 2011 Public Service Commission of Wisconsin (PSCW) 2012 Rates Natural Gas Rate Case Rate Order WPS	Dec. 31, 2012 Michigan Public Service Commission (MPSC) - UPPCO 2012 Rates item	Sep. 30, 2012 Michigan Public Service Commission (MPSC) - UPPCO 2012 Rates Retail Electric Rate Case Settlement agreement	Mar. 31, 2012 Michigan Public Service Commission (MPSC) - UPPCO 2012 Rates Retail Electric Rate Case Settlement agreement	Dec. 20, 2011 Michigan Public Service Commission (MPSC) - UPPCO 2012 Rates Retail Electric Rate Case Settlement agreement	Jul. 31, 2012 Illinois Commerce Commission (ICC) - PGL 2013 Rates Natural Gas Rate Case Entity's Original Request	Mar. 31, 2013 Illinois Commerce Commission (ICC) - PGL 2013 Rates Natural Gas Rate Case Entity's Revised Request	Apr. 26, 2013 Illinois Commerce Commission (ICC) - PGL 2013 Rates Natural Gas Rate Case Regulatory Authority Staff Recommendation	Mar. 31, 2013 Illinois Commerce Commission (ICC) - PGL 2013 Rates Natural Gas Rate Case Regulatory Authority Staff Recommendation	Mar. 31, 2013 Illinois Commerce Commission (ICC) - PGL 2013 Rates Natural Gas Rate Case Rebuttal testimony Maximum	Mar. 31, 2013 Illinois Commerce Commission (ICC) - PGL 2012 Rates	Jan. 10, 2012 Illinois Commerce Commission (ICC) - PGL 2012 Rates Natural Gas Rate Case Rate Order	Jul. 31, 2012 Illinois Commerce Commission (ICC) - NSG 2013 Rates Natural Gas Rate Case Entity's Original Request	Mar. 31, 2013 Illinois Commerce Commission (ICC) - NSG 2013 Rates Natural Gas Rate Case Entity's Revised Request	Apr. 26, 2013 Illinois Commerce Commission (ICC) - NSG 2013 Rates Natural Gas Rate Case Regulatory Authority Staff Recommendation	Mar. 31, 2013 Illinois Commerce Commission (ICC) - NSG 2013 Rates Natural Gas Rate Case Regulatory Authority Staff Recommendation	Mar. 31, 2013 Illinois Commerce Commission (ICC) - NSG 2013 Rates Natural Gas Rate Case Rebuttal testimony Maximum	Mar. 31, 2013 Illinois Commerce Commission (ICC) - NSG 2012 Rates	Jan. 10, 2012 Illinois Commerce Commission (ICC) - NSG 2012 Rates Natural Gas Rate Case Rate Order	Apr. 26, 2013 Illinois Commerce Commission (ICC) - PGL and Illinois Commerce Commission (ICC) - NSG 2013 Rates Natural Gas Rate Case Regulatory Authority Staff Recommendation	Mar. 31, 2013 Illinois Commerce Commission (ICC) - PGL and Illinois Commerce Commission (ICC) - NSG 2013 Rates Natural Gas Rate Case Regulatory Authority Staff Recommendation	Jul. 13, 2012 Minnesota Public Utilities Commission (MPUC) 2011 Rates Natural Gas Rate Case Rate Order	May 31, 2010 Federal Energy Regulatory Commission (FERC) Seams Elimination Charge Adjustment (SECA) Integrys Energy Services item	Mar. 31, 2006 Federal Energy Regulatory Commission (FERC) Seams Elimination Charge Adjustment (SECA) Integrys Energy Services	Mar. 31, 2013 Federal Energy Regulatory Commission (FERC) Seams Elimination Charge Adjustment (SECA) Integrys Energy Services	Jan. 31, 2013 Federal Energy Regulatory Commission (FERC) Settlement agreement Integrys Energy Services	Jan. 31, 2013 Michigan Public Service Commission (MPSC) - MGU
Regulatory Proceedings:
Rate increase (decrease)		$ 71.1	$ 19.0												$ 78.3	$ 97.0						$ 9.8	$ 9.6
Percent return on equity	10.75%														10.75%	10.00%						10.75%	10.00%
Equity ratio percent	51.11%														50.00%							50.00%
Rate increase (decrease)						0	28.5	(3.4)	8.1	(7.2)				4.2							57.8							1.9			11.0
Expenses related to electric decoupling													1.5
Reversal expenses related to electric decoupling												1.5
Estimated fuel refund including carrying costs							20.5																											3.8
Deferred regulatory liability related to employee benefits								2.4
Annual cap on rates							14.0	8.0
Percent return on equity					10.30%									10.20%							9.45%							9.45%			9.70%
Equity ratio percent					51.61%									54.90%							49.00%							50.00%			50.48%
Authorized recovery of income tax amounts previously expensed related to the Federal Health Care Reform Act				5.9
Percentage of price variance from the cost of fuel and purchased power included in rates									2.00%
Trial basis period																															3 years
Transition period when charges paid																																	16 months
Billings received																																	19.2
Rate increase (decrease)																	52.0	12.9	15.4					6.1	3.4	2.6
Percent return on equity																													9.33%	9.06%
Equity ratio percent																	50.43%	50.43%						50.32%	50.32%
Annual cap on distribution revenue														1.50%																	10.00%
Number of decoupling mechanisms in place											0
Favorable rulings, number of issues																																2
Modification of depreciation study as a result of reversal of rulings																																				2.5
Reduction to depreciation expense																																				2.5
Settlement agreement amount																																			9.5
Period from the effective date of agreement within which lump sum payment is to be made																																			5 days
Period from the effective date of agreement within which petitions for review filed with U.S. Court of Appeals is to be withdrawn																																			5 days
Amount expected to be recovered or refunded related to decoupling mechanisms																				$ 14.8							$ 1.7

XML

COMMITMENTS AND CONTINGENCIES (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended	0 Months Ended	1 Months Ended					3 Months Ended
	Mar. 31, 2013 Weston and Pulliam Plants WPS	Apr. 22, 2013 Columbia and Edgewater WPS	Feb. 29, 2012 Pulliam Title V Air Permit WPS	Jun. 30, 2012 Columbia Title V Air Permit WPS	Mar. 31, 2013 WDNR Issued NOV's WPS NOV	Mar. 31, 2013 Mercury emission MW	Mar. 31, 2013 Mercury emission WPS	Mar. 31, 2013 Manufactured Gas Plant Remediation site
Environmental
Beneficial environmental project amount	$ 6.0	$ 1.3
Civil penalty and legal fees	1.2	0.4
EPA Review Period in Days			45 days
Maximum period over which operation permit would be due				6 months
Number of NOV's alleging violations of the air permits received since 2008					4
Number of corrective actions taken for NOV's received					5
Environmental
Percentage mercury reduction required by the State of Wisconsin's mercury rule						40.00%
Level of electric generating units above which a 90% reduction in mercury emissions is required by 2015 (in MW)						150
Percentage mercury reduction required by the State of Wisconsin's mercury rule, for electric generating units above 150 MW						90.00%
Level of electric generating units above which a reduction in mercury emissions is required (in MW)						25
Estimated capital cost to achieve required emission reduction							8
Environmental remediation obligations
Number of environmental remediation sites								53
Number of environmental remediation sites transferred to the EPA Superfund Alternative Sites Program								20
Estimated and accrued future undiscounted investigation and cleanup costs for all sites								639.6
Cash expenditures for environmental remediation not yet recovered in rates								30.0
Regulatory assets recorded for cash and estimated future remediation expenditures, net of insurance recoveries received								669.6
Insurance recoveries received								$ 63.1

XML

LONG-TERM DEBT (Details) (USD $) In Millions, unless otherwise specified					1 Months Ended				1 Months Ended				1 Months Ended			1 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2013 WPS	Dec. 31, 2012 WPS	Feb. 28, 2013 WPS 3.95% Senior Notes due 2013	Mar. 31, 2013 WPS 4.80% Senior Notes due 2013	Mar. 31, 2013 PGL	Dec. 31, 2012 PGL	Apr. 30, 2013 PGL First and Refunding Mortgage Bonds, Series KK, 5.00% bonds due 2033	Apr. 30, 2013 PGL First and Refunding Mortgage Bonds, Series ZZ, 4.00% bonds due 2033	Mar. 31, 2013 PGL First and Refunding Mortgage Bonds, Series NN-2, 4.625% bonds due 2013	Mar. 31, 2013 PGL First and Refunding Mortgage Bonds, Series SS, 7.00% bonds due 2013	Aug. 31, 2013 PGL First and Refunding Mortgage Bonds, Series AAA, 3.96% bonds due 2043 Future funding commitment	Mar. 31, 2013 NSG	Dec. 31, 2012 NSG	May 31, 2013 NSG First Mortgage Series Q, 3.96% bonds due 2043	Mar. 31, 2013 NSG First Mortgage Series N-2, 4.625% bonds due 2013	Mar. 31, 2013 NSG First Mortgage Series O, 7.00% bonds due 2013	Mar. 31, 2013 INTEGRYS ENERGY GROUP, INC.	Dec. 31, 2012 INTEGRYS ENERGY GROUP, INC.
LONG-TERM DEBT
Total	$ 2,224.4	$ 2,246.4	$ 850.1	$ 872.1			$ 625.0	$ 625.0						$ 74.5	$ 74.5				$ 674.8	$ 674.8
Unamortized discount on debt	(1.2)	(1.2)
Total debt	2,223.2	2,245.2
Less current portion	(291.5)	(313.5)				(125.0)					(75.0)	(45.0)					(40.0)	(6.5)
Total long-term debt	1,931.7	1,931.7
Interest rate stated percentage					3.95%	4.80%			5.00%	4.00%	4.625%	7.00%	3.96%			3.96%	4.625%	7.00%
Principal balance repaid					22.0				50.0
Maturity term													30 years
Amount of debt issued										$ 50.0			$ 220.0			$ 54.0

XML

DISCONTINUED OPERATIONS (Tables)

3 Months Ended

Mar. 31, 2013

Combined Locks

Discontinued operations

Carrying values of major classes of assets and liabilities classified as held for sale on balance sheets

(Millions)	March 31, 2013		December 31, 2012
Inventories	$	0.5	$	0.5
Property, plant, and equipment, net of accumulated depreciation of $0.5 million	2.0		2.0
Total assets	$	2.5	$	2.5

Components of discontinued operations recorded on the income statements

(Millions)	2013			2012
Nonregulated revenues	$	—		$	0.4
Nonregulated cost of sales	(0.1		)	(0.3		)
Operating and maintenance expense	(0.1		)	(0.2		)
Depreciation and amortization expense	—			(0.1		)
Taxes other than income taxes	—			(0.1		)
Loss before taxes	(0.2		)	(0.3		)
Benefit for income taxes	0.1			0.1
Discontinued operations, net of tax	$	(0.1	)	$	(0.2	)

WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC

Discontinued operations

Carrying values of major classes of assets and liabilities classified as held for sale on balance sheets

(Millions)	As of the Closing Date on March 14, 2013		As of December 31, 2012
Inventories	$	1.8	$	1.8
Other current assets	0.2		—
Property, plant, and equipment	5.7		5.7
Other long-term assets	0.1		0.1
Total assets	$	7.8	$	7.6
Total liabilities – other current liabilities	$	0.4	$	0.2

Components of discontinued operations recorded on the income statements

(Millions)	2013			2012
Nonregulated revenues	$	1.2		$	(0.7	)
Nonregulated cost of sales	(0.9		)	(0.4		)
Operating and maintenance expense *	0.4			(0.5		)
Depreciation and amortization expense	—			(0.2		)
Taxes other than income taxes	(0.3		)	(0.8		)
Income (loss) before taxes	0.4			(2.6		)
(Provision) benefit for income taxes	(0.2		)	1.0
Discontinued operations, net of tax	$	0.2		$	(1.6	)

* Includes a $1.0 million gain on sale at closing.

WPS Westwood Generation, LLC

Discontinued operations

Components of discontinued operations recorded on the income statements

(Millions)	2012
Nonregulated revenues	$	4.1
Nonregulated cost of sales	(1.3		)
Operating and maintenance expense	(1.0		)
Depreciation and amortization expense	(0.3		)
Taxes other than income taxes	(0.1		)
Interest expense	(0.1		)
Income before taxes	1.3
Provision for income taxes	(0.5		)
Discontinued operations, net of tax	$	0.8

XML

RISK MANAGEMENT ACTIVITIES (Details 3) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Risk management activities
Cash collateral provided to others, related to contracts under master netting or similar arrangements	$ 24.3	$ 39.9
Cash collateral provided to others, other	1.1	1.1
Cash collateral received from others related to contracts under master netting or similar arrangements		0.2
Integrys Energy Services
Risk management activities
Aggregate fair value of credit-risk derivative instruments	67.2	108.9
Collateral that would have been required:	124.6	173.8
Collateral already satisfied, Letters of credit	3.2	3.2
Collateral remaining:	121.4	170.6
Utility Segments
Risk management activities
Aggregate fair value of credit-risk derivative instruments	3.8	14.0
Collateral that would have been required:	0.4	10.1
Collateral remaining:	$ 0.4	$ 10.1

XML

EMPLOYEE BENEFITS PLANS

3 Months Ended

Mar. 31, 2013

EMPLOYEE BENEFITS PLANS

EMPLOYEE BENEFITS PLANS

NOTE 14 — EMPLOYEE BENEFITS PLANS

The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans:

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended, March 31,						Three Months Ended, March 31,
(Millions)	2013			2012			2013			2012
Service cost	$	7.5		$	12.4		$	6.5		$	5.5
Interest cost	17.8			19.8			6.3			7.2
Expected return on plan assets	(26.6		)	(27.1		)	(7.7		)	(7.0		)
Amortization of transition obligation	—			—			—			0.1
Amortization of prior service cost (credit)	1.0			1.2			(0.6		)	(0.9		)
Amortization of net actuarial loss	13.5			8.3			2.0			1.6
Net periodic benefit cost	$	13.2		$	14.6		$	6.5		$	6.5

Transition obligations, prior service costs (credits), and net actuarial losses that have not yet been recognized as a component of net periodic benefit cost are included in accumulated OCI for our nonregulated entities and are recorded as net regulatory assets for our utilities.

We make contributions to our plans in accordance with legal and tax requirements. These contributions do not necessarily occur evenly throughout the year. During the three months ended March 31, 2013, we contributed $63.2 million to our pension plans and contributions to our other postretirement benefit plans were not significant. We expect to contribute an additional $4.7 million to our pension plans and $32.8 million to our other postretirement benefit plans during the remainder of 2013, dependent upon various factors affecting us, including our liquidity position and tax law changes.

XML

FAIR VALUE

3 Months Ended

Mar. 31, 2013

FAIR VALUE

FAIR VALUE

NOTE 19 — FAIR VALUE

Fair Value Measurements

The following tables show assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:

	March 31, 2013
(Millions)	Level 1		Level 2		Level 3		Total
Assets
Risk Management Assets
Utility Segments
Natural gas contracts	$	1.2	$	10.5	$	—	$	11.7
Financial transmission rights (FTRs)	—		—		1.0		1.0
Petroleum product contracts	0.1		—		—		0.1
Coal contracts	—		—		0.1		0.1
Nonregulated Segments
Natural gas contracts	10.2		21.2		2.9		34.3
Electric contracts	64.0		107.9		13.7		185.6
Total Risk Management Assets	$	75.5	$	139.6	$	17.7	$	232.8
Investment in exchange-traded funds	$	12.4	$	—	$	—	$	12.4
Liabilities
Risk Management Liabilities
Utility Segments
Natural gas contracts	$	—	$	3.8	$	—	$	3.8
FTRs	—		—		0.1		0.1
Coal contracts	—		0.1		4.7		4.8
Nonregulated Segments
Natural gas contracts	9.0		14.8		1.2		25.0
Electric contracts	78.6		70.3		7.6		156.5
Total Risk Management Liabilities	$	87.6	$	89.0	$	13.6	$	190.2

	December 31, 2012
(Millions)	Level 1		Level 2		Level 3		Total
Assets
Risk Management Assets
Utility Segments
Natural gas contracts	$	0.3	$	3.1	$	—	$	3.4
FTRs	—		—		2.1		2.1
Petroleum product contracts	0.2		—		—		0.2
Coal contracts	—		—		2.5		2.5
Nonregulated Segments
Natural gas contracts	21.4		36.4		5.4		63.2
Electric contracts	48.4		61.3		9.6		119.3
Total Risk Management Assets	$	70.3	$	100.8	$	19.6	$	190.7
Investment in exchange-traded funds	$	11.8	$	—	$	—	$	11.8
Liabilities
Risk Management Liabilities
Utility Segments
Natural gas contracts	$	1.1	$	14.1	$	—	$	15.2
FTRs	—		—		0.1		0.1
Coal contracts	—		—		9.0		9.0
Nonregulated Segments
Natural gas contracts	17.7		36.9		1.5		56.1
Electric contracts	54.9		91.1		13.9		159.9
Total Risk Management Liabilities	$	73.7	$	142.1	$	24.5	$	240.3

The risk management assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices and interest rates. For more information on derivative instruments, see Note 3, “Risk Management Activities.”

The following tables show net risk management assets (liabilities) transferred between the levels of the fair value hierarchy:

	Nonregulated Segments — Natural Gas Contracts
	Three Months Ended March 31, 2013						Three Months Ended March 31, 2012
(Millions)	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Transfers into Level 1 from	N/A		$	—	$	—	N/A		$	—	$	—
Transfers into Level 2 from	$	—	N/A		—		$	—	N/A		1.3
Transfers into Level 3 from	—		0.2		N/A		—		2.4		N/A

	Nonregulated Segments — Electric Contracts
	Three Months Ended March 31, 2013						Three Months Ended March 31, 2012
(Millions)	Level 1		Level 2		Level 3		Level 1		Level 2			Level 3
Transfers into Level 1 from	N/A		$	—	$	—	N/A		$	—		$	—
Transfers into Level 2 from	$	—	N/A		5.5		$	—	N/A			(0.1		)
Transfers into Level 3 from	—		—		N/A		—		(5.0		)	N/A

Derivatives are transferred between the levels of the fair value hierarchy primarily due to changes in the source of data used to construct price curves as a result of changes in market liquidity.

The significant unobservable inputs used in the valuation that resulted in categorization within Level 3 were as follows at March 31, 2013. The amounts and percentages listed in the table below represent the range of unobservable inputs that individually had a significant impact on the fair value determination and caused a derivative transaction to be classified as Level 3.

	Fair Value (Millions)
	Assets		Liabilities		Valuation Technique	Unobservable Input	Average or Range
Utility Segments
FTRs	$	1.0	$	0.1	Market-based	Forward market prices ($/megawatt-month) (1)	203.72
Coal contracts	0.1		4.7		Market-based	Forward market prices ($/ton) (2)	11.64 — 13.90
Nonregulated Segments
Natural gas contracts	2.9		1.2		Market-based	Forward market prices ($/dekatherm) (3)	(0.08) — 1.99
						Probability of default	11.6% — 51.0%
Electric contracts	13.7		7.6		Market-based	Forward market prices ($/megawatt-hours) (3)	(9.55) — 44.03
						Option volatilities (4)	19.0% — 80.0%

⁽¹⁾  Represents forward market prices developed using historical cleared pricing data from MISO used in the valuation of FTRs.

⁽²⁾  Represents third-party forward market pricing used in the valuation of our coal contracts.

⁽³⁾  Represents unobservable basis spreads developed using historical settled prices that are applied to observable market prices at various natural gas and electric locations, as well as unobservable adjustments made to extend observable market prices beyond the quoted period through the end of the transaction term.

⁽⁴⁾  Represents the range of volatilities used in the valuation of options.

Significant changes in historical settlement prices, forward commodity prices, and option volatilities would result in a directionally similar significant change in fair value. Significant changes in probability of default would result in a significant directionally opposite change in fair value. Changes in the adjustments to prices related to monthly curve shaping would affect fair value differently depending on their direction.

The following tables set forth a reconciliation of changes in the fair value of items categorized as Level 3 measurements:

Three Months Ended March 31, 2013	Nonregulated Segments						Utility Segments
(Millions)	Natural Gas			Electric			FTRs			Coal Contracts			Total
Balance at the beginning of the period	$	3.9		$	(4.3	)	$	2.0		$	(6.5	)	$	(4.9	)
Net realized and unrealized (losses) gains included in earnings	(1.5		)	15.1			0.3			—			13.9
Net unrealized (losses) gains recorded as regulatory assets or liabilities	—			—			(0.2		)	3.1			2.9
Purchases	—			0.7			—			—			0.7
Settlements	(0.9		)	0.1			(1.2		)	(1.2		)	(3.2		)
Net transfers into Level 3	0.2			—			—			—			0.2
Net transfers out of Level 3	—			(5.5		)	—			—			(5.5		)
Balance at the end of the period	$	1.7		$	6.1		$	0.9		$	(4.6	)	$	4.1
Net unrealized (losses) gains included in earnings related to instruments still held at the end of the period	$	(1.5	)	$	15.1		$	—		$	—		$	13.6

Three Months Ended March 31, 2012	Nonregulated Segments						Utility Segments
(Millions)	Natural Gas			Electric			FTRs			Coal Contract			Total
Balance at the beginning of the period	$	8.3		$	(11.5	)	$	2.2		$	(6.9	)	$	(7.9	)
Net realized and unrealized gains (losses) included in earnings	4.1			(7.7		)	0.5			—			(3.1		)
Net unrealized gains (losses) recorded as regulatory assets or liabilities	—			—			0.1			(5.8		)	(5.7		)
Purchases	—			1.1			—			—			1.1
Sales	—			—			(0.1		)	—			(0.1		)
Settlements	(2.6		)	1.1			(1.8		)	(0.7		)	(4.0		)
Net transfers into Level 3	2.4			(5.0		)	—			—			(2.6		)
Net transfers out of Level 3	(1.3		)	0.1			—			—			(1.2		)
Balance at the end of the period	$	10.9		$	(21.9	)	$	0.9		$	(13.4	)	$	(23.5	)
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	$	4.1		$	(7.7	)	$	—		$	—		$	(3.6	)

Unrealized gains and losses included in earnings related to Integrys Energy Services’ risk management assets and liabilities are recorded through nonregulated revenue on the statements of income. Realized gains and losses on these same instruments are recorded in nonregulated revenue or nonregulated cost of sales, depending on the nature of the instrument. Unrealized gains and losses on Level 3 derivatives at the utilities are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through utility cost of fuel, natural gas, and purchased power on the statements of income.

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:

	March 31, 2013				December 31, 2012
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	2,223.2	$	2,376.2	$	2,245.2	$	2,425.8
Preferred stock of subsidiary	51.1		61.7		51.1		52.7

The fair values of long-term debt instruments are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. The fair values of preferred stock are estimated based on quoted market prices when available, or by using a perpetual dividend discount model. The fair values of long-term debt instruments and preferred stock are categorized within Level 2 of the fair value hierarchy.

Due to the short-term nature of cash and cash equivalents, accounts receivable, accounts payable, notes payable, and outstanding commercial paper, the carrying amount for each such item approximates fair value.

XML

RISK MANAGEMENT ACTIVITIES (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Derivative assets and liabilities from risk management activities
Current assets from risk management activities	$ 182.5	$ 145.4
Long-term Assets from Risk Management Activities	50.3	45.3
Current Liabilities from Risk Management Activities	140.9	181.9
Long-term Liabilities from Risk Management Activities	49.3	58.4
Risk Management Assets	232.8	190.7
Risk Management Liabilities	190.2	240.3
Utility Segments | Cash flow hedges | Natural gas contracts
Derivative assets and liabilities from risk management activities
Current Liabilities from Risk Management Activities	0.1	0.4
Utility Segments | Nonhedge derivatives | Natural gas contracts
Derivative assets and liabilities from risk management activities
Current assets from risk management activities	9.8	2.5
Long-term Assets from Risk Management Activities	1.9	0.9
Current Liabilities from Risk Management Activities	3.7	14.0
Long-term Liabilities from Risk Management Activities		0.8
Utility Segments | Nonhedge derivatives | FTRs
Derivative assets and liabilities from risk management activities
Current assets from risk management activities	1.0	2.1
Current Liabilities from Risk Management Activities	0.1	0.1
Utility Segments | Nonhedge derivatives | Petroleum product contracts
Derivative assets and liabilities from risk management activities
Current assets from risk management activities	0.1	0.2
Utility Segments | Nonhedge derivatives | Coal contract
Derivative assets and liabilities from risk management activities
Current assets from risk management activities	0.1	0.3
Long-term Assets from Risk Management Activities		2.2
Current Liabilities from Risk Management Activities	2.8	4.7
Long-term Liabilities from Risk Management Activities	2.0	4.3
Nonregulated Segments | Nonhedge derivatives | Natural gas contracts
Derivative assets and liabilities from risk management activities
Current assets from risk management activities	24.3	51.7
Long-term Assets from Risk Management Activities	10.0	11.5
Current Liabilities from Risk Management Activities	19.7	48.5
Long-term Liabilities from Risk Management Activities	5.3	7.6
Nonregulated Segments | Nonhedge derivatives | Electric contracts
Derivative assets and liabilities from risk management activities
Current assets from risk management activities	147.2	88.6
Long-term Assets from Risk Management Activities	38.4	30.7
Current Liabilities from Risk Management Activities Including Amounts Classified As Held For Sale	114.5	114.2
Long-term Liabilities from Risk Management Activities	$ 42.0	$ 45.7

XML

GUARANTEES (Tables)

3 Months Ended

Mar. 31, 2013

GUARANTEES

Schedule of outstanding guarantees

	Total Amounts Committed at March 31, 2013		Expiration
(Millions)			Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees supporting commodity transactions of subsidiaries (1)	$	597.1	$	368.8	$	31.3	$	197.0
Standby letters of credit (2)	34.2		34.1		0.1		—
Surety bonds (3)	14.4		14.4		—		—
Other guarantees (4)	22.3		—		—		22.3
Total guarantees	$	668.0	$	417.3	$	31.4	$	219.3

⁽¹⁾  Consists of parental guarantees of $436.3 million to support the business operations of Integrys Energy Services; $108.5 million and $45.3 million, respectively, related to natural gas supply at MERC and MGU; and $5.0 million at IBS, and $2.0 million at UPPCO to support business operations. These guarantees are not reflected on our balance sheets.

⁽²⁾  At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. This amount consists of $32.5 million issued to support Integrys Energy Services’ operations and $1.7 million issued to support MERC, MGU, NSG, PGL, Pinnacle CNG Systems, UPPCO, and WPS. These amounts are not reflected on our balance sheets.

⁽³⁾  Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These guarantees are not reflected on our balance sheets.

⁽⁴⁾  Consists of (a) $10.0 million related to the sale agreement for Integrys Energy Services’ Texas retail marketing business, which included a number of customary representations, warranties, and indemnification provisions. An insignificant liability was recorded related to the possible imposition of additional miscellaneous gross receipts tax in the event of a change in law or interpretation of the tax law; (b) $5.0 million related to an environmental indemnification provided by Integrys Energy Services as part of the sale of the Stoneman generation facility, under which we expect that the likelihood of required performance is remote. This amount is not reflected on our balance sheets; and (c) $7.3 million related to other indemnifications primarily for workers compensation coverage. These amounts are not reflected on our balance sheets.

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Assets
Cash and cash equivalents	$ 72.0	$ 27.4
Collateral on deposit	25.4	41.0
Accounts receivable and accrued unbilled revenues, net of reserves of $47.2 and $43.5, respectively	899.0	796.8
Inventories	140.2	271.9
Assets from risk management activities	182.5	145.4
Regulatory assets	88.4	110.8
Assets held for sale	2.5	10.1
Deferred income taxes	42.8	64.3
Prepaid taxes	116.6	152.8
Other current assets	31.3	38.6
Current assets	1,600.7	1,659.1
Property, plant, and equipment, net of accumulated depreciation of $3,225.5 and $3,114.7, respectively	5,941.8	5,501.9
Regulatory assets	1,842.7	1,813.8
Assets from risk management activities	50.3	45.3
Equity method investments	518.3	512.2
Goodwill	658.3	658.3
Other long-term assets	152.3	136.8
Total assets	10,764.4	10,327.4
Liabilities and Equity
Short-term debt	756.4	482.4
Current portion of long-term debt	291.5	313.5
Accounts payable	450.1	457.7
Liabilities from risk management activities	140.9	181.9
Accrued taxes	95.9	83.0
Regulatory liabilities	84.8	65.6
Liabilities held for sale		0.2
Other current liabilities	287.1	229.0
Current liabilities	2,106.7	1,813.3
Long-term debt	1,931.7	1,931.7
Deferred income taxes	1,263.9	1,203.8
Deferred investment tax credits	48.9	49.3
Regulatory liabilities	377.6	370.5
Environmental remediation liabilities	641.2	651.5
Pension and other postretirement benefit obligations	566.4	625.2
Liabilities from risk management activities	49.3	58.4
Asset retirement obligations	416.3	411.2
Other long-term liabilities	138.3	135.7
Long-term liabilities	5,433.6	5,437.3
Commitments and contingencies
Common stock - $1 par value; 200,000,000 shares authorized; 78,809,948 shares issued; 78,353,096 shares outstanding	78.8	78.3
Additional paid-in capital	2,590.2	2,574.6
Retained earnings	565.4	431.5
Accumulated other comprehensive loss	(39.3)	(40.9)
Shares in deferred compensation trust	(22.0)	(17.7)
Total common shareholders' equity	3,173.1	3,025.8
Preferred stock of subsidiary - $100 par value; 1,000,000 shares authorized; 511,882 shares issued; 510,495 shares outstanding	51.1	51.1
Noncontrolling interest in subsidiaries	(0.1)	(0.1)
Total liabilities and equity	$ 10,764.4	$ 10,327.4

XML

RISK MANAGEMENT ACTIVITIES

3 Months Ended

Mar. 31, 2013

RISK MANAGEMENT ACTIVITIES

RISK MANAGEMENT ACTIVITIES

NOTE 3 — RISK MANAGEMENT ACTIVITIES

The following tables show our assets and liabilities from risk management activities:

		March 31, 2013
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Utility Segments
Nonhedge derivatives
Natural gas contracts	Current	$	9.8	$	3.7
Natural gas contracts	Long-term	1.9		—
Financial transmission rights (FTRs)	Current	1.0		0.1
Petroleum product contracts	Current	0.1		—
Coal contracts	Current	0.1		2.8
Coal contracts	Long-term	—		2.0
Cash flow hedges
Natural gas contracts	Current	—		0.1
Nonregulated Segments
Nonhedge derivatives
Natural gas contracts	Current	24.3		19.7
Natural gas contracts	Long-term	10.0		5.3
Electric contracts	Current	147.2		114.5
Electric contracts	Long-term	38.4		42.0
	Current	182.5		140.9
	Long-term	50.3		49.3
Total		$	232.8	$	190.2

*   We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

		December 31, 2012
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Utility Segments
Nonhedge derivatives
Natural gas contracts	Current	$	2.5	$	14.0
Natural gas contracts	Long-term	0.9		0.8
FTRs	Current	2.1		0.1
Petroleum product contracts	Current	0.2		—
Coal contracts	Current	0.3		4.7
Coal contracts	Long-term	2.2		4.3
Cash flow hedges
Natural gas contracts	Current	—		0.4
Nonregulated Segments
Nonhedge derivatives
Natural gas contracts	Current	51.7		48.5
Natural gas contracts	Long-term	11.5		7.6
Electric contracts	Current	88.6		114.2
Electric contracts	Long-term	30.7		45.7
	Current	145.4		181.9
	Long-term	45.3		58.4
Total		$	190.7	$	240.3

*   We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

The following tables show the potential effect of netting arrangements on our financial position for recognized derivative assets and liabilities:

	March 31, 2013
(Millions)	Gross Amount		Gross Amount Not Offset in the Balance Sheet, including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements
Utility Segments	$	12.8	$	3.4	$	9.4
Nonregulated Segments	219.7		160.3		59.4
Total	232.5		163.7		68.8
Derivative assets not subject to master netting or similar arrangements	0.3				0.3
Total risk management assets	$	232.8			$	69.1
Derivative liabilities subject to master netting or similar arrangements
Utility Segments	$	3.9	$	3.4	$	0.5
Nonregulated Segments	181.4		160.3		21.1
Total	185.3		163.7		21.6
Derivative liabilities not subject to master netting or similar arrangements	4.9				4.9
Total risk management liabilities	$	190.2			$	26.5

	December 31, 2012
(Millions)	Gross Amount		Gross Amount Not Offset in the Balance Sheet, including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements
Utility Segments	$	5.7	$	3.0	$	2.7
Nonregulated Segments	182.5		145.4		37.1
Total	188.2		148.4		39.8
Derivative assets not subject to master netting or similar arrangements	2.5				2.5
Total risk management assets	$	190.7			$	42.3
Derivative liabilities subject to master netting or similar arrangements
Utility Segments	$	15.3	$	3.8	$	11.5
Nonregulated Segments	215.4		159.8		55.6
Total	230.7		163.6		67.1
Derivative liabilities not subject to master netting or similar arrangements	9.6				9.6
Total risk management liabilities	$	240.3			$	76.7

Our master netting and similar arrangements have conditional rights of setoff that can be enforced under a variety of situations, including counterparty default or credit rating downgrade below investment grade. Financial collateral received or provided is restricted to the extent that is it required per the terms of the related agreements. We have trade receivables and trade payables, subject to master netting or similar arrangements, that are not included in the above table. These amounts may offset (or conditionally offset) the net amounts presented in the above table. The net amounts in the above table represent the netting of fair value balances under master netting or similar arrangements, and the netting of cash collateral, as applicable.

The following table shows our cash collateral positions:

(Millions)	March 31, 2013		December 31, 2012
Cash collateral provided to others:
Related to contracts under master netting or similar arrangements	$	24.3	$	39.9
Other	1.1		1.1
Cash collateral received from others related to contracts under master netting or similar arrangements *	—		0.2

*   Reflected in other current liabilities on the balance sheets.

Certain of our derivative and nonderivative commodity instruments contain provisions that could require “adequate assurance” in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The following table shows the aggregate fair value of all derivative instruments with specific credit risk related contingent features that were in a liability position:

(Millions)	March 31, 2013		December 31, 2012
Integrys Energy Services	$	67.2	$	108.9
Utility segments	3.8		14.0

If all of the credit risk related contingent features contained in commodity instruments (including derivatives, nonderivatives, normal purchase and normal sales contracts, and applicable payables and receivables) had been triggered, our collateral requirement would have been as follows:

(Millions)	March 31, 2013		December 31, 2012
Collateral that would have been required:
Integrys Energy Services	$	124.6	$	173.8
Utility segments	0.4		10.1
Collateral already satisfied:
Integrys Energy Services — Letters of credit	3.2		3.2
Collateral remaining:
Integrys Energy Services	121.4		170.6
Utility segments	0.4		10.1

Utility Segments

Non-Hedge Derivatives

Utility derivatives include natural gas purchase contracts, coal purchase contracts, financial derivative contracts (futures, options, and swaps), and FTRs used to manage electric transmission congestion costs. Both the electric and natural gas utility segments use futures, options, and swaps to manage the risks associated with the market price volatility of natural gas supply costs, and the costs of gasoline and diesel fuel used by utility vehicles. The electric utility segment also uses oil futures and options to manage price risk related to coal transportation.

The utilities had the following notional volumes of outstanding nonhedge derivative contracts:

	March 31, 2013			December 31, 2012
	Purchases	Sales	Other Transactions	Purchases	Sales	Other Transactions
Natural gas (millions of therms)	595.4	—	N/A	1,072.6	0.1	N/A
FTRs (millions of kilowatt-hours)	N/A	N/A	1,579.0	N/A	N/A	4,057.2
Petroleum products (barrels)	50,855.0	N/A	N/A	62,811.0	N/A	N/A
Coal contracts (millions of tons)	4.7	0.2	N/A	5.1	N/A	N/A

The table below shows the unrealized gains (losses) recorded related to nonhedge derivatives at the utilities:

		Three Months Ended March 31
(Millions)	Financial Statement Presentation	2013			2012
Natural gas contracts	Balance Sheet — Regulatory assets (current)	$	13.0		$	(6.4	)
Natural gas contracts	Balance Sheet — Regulatory assets (long-term)	0.8			(0.8		)
Natural gas contracts	Balance Sheet — Regulatory liabilities (current)	5.9			(3.7		)
Natural gas contracts	Balance Sheet — Regulatory liabilities (long-term)	0.8			0.1
Natural gas contracts	Income Statement — Utility cost of fuel, natural gas, and purchased power	—			0.1
Natural gas contracts	Income Statement — Operating and maintenance expense	0.2			—
FTRs	Balance Sheet — Regulatory assets (current)	0.2			0.4
FTRs	Balance Sheet — Regulatory liabilities (current)	(0.4		)	(0.3		)
Petroleum product contracts	Balance Sheet — Regulatory assets (current)	—			0.1
Petroleum product contracts	Balance Sheet — Regulatory liabilities (current)	—			0.1
Petroleum product contracts	Income Statement — Operating and maintenance expense	—			0.1
Coal contracts	Balance Sheet — Regulatory assets (current)	1.9			(3.1		)
Coal contracts	Balance Sheet — Regulatory assets (long-term)	2.3			(3.5		)
Coal contracts	Balance Sheet — Regulatory liabilities (current)	(0.2		)	—
Coal contracts	Balance Sheet — Regulatory liabilities (long-term)	(2.2		)	—

Nonregulated Segments

NonHedge Derivatives

Integrys Energy Services enters into derivative contracts such as futures, forwards, options, and swaps that are used to manage commodity price risk primarily associated with retail electric and natural gas customer contracts.

Integrys Energy Services had the following notional volumes of outstanding nonhedge derivative contracts:

	March 31, 2013		December 31, 2012
(Millions)	Purchases	Sales	Purchases	Sales
Commodity contracts
Natural gas (therms)	641.5	556.2	782.0	679.0
Electric (kilowatt-hours)	56,100.1	34,502.0	54,127.6	31,809.6
Foreign exchange contracts (Canadian dollars)	0.4	0.4	0.4	0.4

Gains (losses) related to nonhedge derivatives are recognized currently in earnings, as shown in the table below:

		Three Months Ended March 31
(Millions)	Income Statement Presentation	2013			2012
Natural gas contracts	Nonregulated revenue	$	3.4		$	4.0
Natural gas contracts	Nonregulated cost of sales	(1.6		)	—
Natural gas contracts	Nonregulated revenue (reclassified from accumulated OCI) *	(0.1		)	(1.2		)
Electric contracts	Nonregulated revenue	64.0			(68.6		)
Electric contracts	Nonregulated revenue (reclassified from accumulated OCI) *	(1.0		)	(0.7		)
Total		$	64.7		$	(66.5	)

* Represents amounts reclassified from accumulated OCI related to cash flow hedges that were dedesignated in prior periods.

In the next 12 months, pre-tax losses of $0.1 million and $2.4 million related to discontinued cash flow hedges of natural gas contracts and electric contracts, respectively, are expected to be recognized in earnings as the forecasted transactions occur. These amounts are expected to be offset by the settlement of the related nonderivative customer contracts.

XML

INVESTMENT IN ATC (Details 2) (ATC, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
ATC
Income statement data
Revenues	$ 151.8	$ 147.7
Operating expenses	69.8	69.6
Other expense	21.5	20.0
Net income	60.5	58.1
Balance sheet data
Current assets	69.3		63.1
Noncurrent assets	3,325.3		3,274.7
Total assets	3,394.6		3,337.8
Current liabilities	261.5		251.5
Long-term debt	1,550.0		1,550.0
Other noncurrent liabilities	124.8		95.8
Shareholders' equity	1,458.3		1,440.5
Total liabilities and shareholders' equity	$ 3,394.6		$ 3,337.8

XML

FAIR VALUE (Details 4) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation Calculation
Balance at the beginning of the period	$ (4.9)	$ (7.9)
Net realized and unrealized (losses) gains included in earnings	13.9	(3.1)
Net unrealized (losses) gains recorded as regulatory assets or liabilities	2.9	(5.7)
Purchases	0.7	1.1
Sales		(0.1)
Settlements	(3.2)	(4.0)
Net transfers into Level 3	0.2	(2.6)
Net transfers out of Level 3	(5.5)	(1.2)
Balance at the end of the period	4.1	(23.5)
Net unrealized (losses) gains included in earnings related to instruments still held at the end of the period	13.6	(3.6)
Nonregulated Segments | Natural gas contracts
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation Calculation
Balance at the beginning of the period	3.9	8.3
Net realized and unrealized (losses) gains included in earnings	(1.5)	4.1
Settlements	(0.9)	(2.6)
Net transfers into Level 3	0.2	2.4
Net transfers out of Level 3		(1.3)
Balance at the end of the period	1.7	10.9
Net unrealized (losses) gains included in earnings related to instruments still held at the end of the period	(1.5)	4.1
Nonregulated Segments | Electric contracts
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation Calculation
Balance at the beginning of the period	(4.3)	(11.5)
Net realized and unrealized (losses) gains included in earnings	15.1	(7.7)
Purchases	0.7	1.1
Settlements	0.1	1.1
Net transfers into Level 3		(5.0)
Net transfers out of Level 3	(5.5)	0.1
Balance at the end of the period	6.1	(21.9)
Net unrealized (losses) gains included in earnings related to instruments still held at the end of the period	15.1	(7.7)
Utility Segments | FTRs
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation Calculation
Balance at the beginning of the period	2.0	2.2
Net realized and unrealized (losses) gains included in earnings	0.3	0.5
Net unrealized (losses) gains recorded as regulatory assets or liabilities	(0.2)	0.1
Sales		(0.1)
Settlements	(1.2)	(1.8)
Balance at the end of the period	0.9	0.9
Utility Segments | Coal contract
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation Calculation
Balance at the beginning of the period	(6.5)	(6.9)
Net unrealized (losses) gains recorded as regulatory assets or liabilities	3.1	(5.8)
Settlements	(1.2)	(0.7)
Balance at the end of the period	$ (4.6)	$ (13.4)

XML

STOCK-BASED COMPENSATION (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Stock-based compensation expense and the related deferred tax benefit recognized in income
Total stock-based compensation expense	$ 5.7	$ 4.7
Deferred income tax benefit	2.3	1.9
Amount of stock-based compensation cost capitalized	0	0
Stock Options
Stock-based compensation expense and the related deferred tax benefit recognized in income
Total stock-based compensation expense	0.4	0.4
Performance Stock Rights
Stock-based compensation expense and the related deferred tax benefit recognized in income
Total stock-based compensation expense	2.2	1.2
Restricted Share Units
Stock-based compensation expense and the related deferred tax benefit recognized in income
Total stock-based compensation expense	2.8	2.1
Nonemployee director deferred stock units
Stock-based compensation expense and the related deferred tax benefit recognized in income
Total stock-based compensation expense	$ 0.3	$ 1.0

XML

ADVERTISING COSTS

3 Months Ended

Mar. 31, 2013

ADVERTISING COSTS

ADVERTISING COSTS

NOTE 20 — ADVERTISING COSTS

Costs associated with certain natural gas and electric direct-response advertising campaigns at Integrys Energy Services were capitalized and reported as other long-term assets on the balance sheets. The capitalized costs result in probable future benefits and were incurred to solicit sales to customers who could be shown to have responded specifically to the advertising. Capitalized direct-response advertising costs, net of accumulated amortization, totaled $4.1 million and $5.5 million as of March 31, 2013, and December 31, 2012, respectively. The asset balances for each of the direct-response advertising cost pools are reviewed quarterly for impairment, and there was no impairment during the three months ended March 31, 2013, and 2012.

Direct-response advertising costs are amortized to operating and maintenance expense over the estimated period of benefit, which is approximately two years. The amortization of direct-response advertising costs was $3.0 million and $1.0 million for the three months ended March 31, 2013, and 2012, respectively.

We expense all advertising costs as incurred, except for those capitalized as direct-response advertising, as discussed above. Other advertising expense was $2.3 million and $1.7 million, for the three months ended March 31, 2013, and 2012, respectively.

XML

COMMON EQUITY (Details 3) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Dividend Payment Restrictions
Total restricted net assets	1,676.0
Equity in undistributed earnings of 50% or less owned investees accounted under equity method investments	129.4
Maximum
Dividend Payment Restrictions
Debt to capitalization ratio required to be maintained (as a percent)	65.00%
Cumulative period of interest payment deferral on Junior Subordinated Notes	10 years
Minimum
Dividend Payment Restrictions
Number of periods which can be deferred on Junior Subordinated Notes	1
WPS | Maximum
Dividend Payment Restrictions
Percentage of previous period's dividend as restriction on current period dividends	103.00%
Percentage of common stockholders equity to total capitalization for dividend payment restrictions	25.00%
Debt to capitalization ratio required to be maintained (as a percent)	65.00%
WPS | Minimum
Dividend Payment Restrictions
Common equity ratio required to be maintained (as a percent)	51.00%
PGL | Maximum
Dividend Payment Restrictions
Debt to capitalization ratio required to be maintained (as a percent)	65.00%

XML

LONG-TERM DEBT (Tables)

3 Months Ended

Mar. 31, 2013

LONG-TERM DEBT

Disclosure of long-term debt instruments

(Millions)	March 31, 2013			December 31, 2012
WPS (1)	$	850.1		$	872.1
PGL (2)	625.0			625.0
NSG (3)	74.5			74.5
Integrys Energy Group	674.8			674.8
Total	2,224.4			2,246.4
Unamortized discount on debt	(1.2		)	(1.2		)
Total debt	2,223.2			2,245.2
Less current portion	(291.5		)	(313.5		)
Total long-term debt	$	1,931.7		$	1,931.7

⁽¹⁾  In February 2013, WPS’s $22.0 million of 3.95% Senior Notes matured, and the outstanding principal balance was repaid.

In December 2013, WPS’s 4.80% Senior Notes will mature. As a result, the $125.0 million balance of these notes was included in the current portion of long-term debt on our balance sheets.

⁽²⁾  In April 2013, PGL bought back its $50.0 million of 5.00% Series KK First and Refunding Mortgage Bonds that were due in February 2033.

In the same month, PGL issued $50.0 million of 4.00% Series ZZ First and Refunding Mortgage Bonds. These bonds are due in February 2033.

On May 1, 2013, PGL’s 4.625% Series NN-2 First and Refunding Mortgage Bonds matured, and the outstanding principal balance was repaid. As a result, the $75.0 million balance of these bonds was included in the current portion of long-term debt on our balance sheets.

In November 2013, PGL’s 7.00% Series SS First and Refunding Mortgage Bonds will mature. As a result, the $45.0 million balance of these bonds was included in the current portion of long-term debt on our balance sheets.

⁽³⁾  On May 1, 2013, NSG issued $54.0 million of 3.96% Series Q First Mortgage Bonds. These bonds are due in May 2043.

On May 1, 2013, NSG’s 4.625% Series N-2 First Mortgage Bonds matured, and the outstanding principal balance was repaid. As a result, the $40.0 million balance of these bonds was included in the current portion of long-term debt on our balance sheets.

In November 2013, NSG’s 7.00% Series O First Mortgage Bonds will mature. As a result, the $6.5 million balance of these bonds was included in the current portion of long-term debt on our balance sheets.

XML

GUARANTEES

3 Months Ended

Mar. 31, 2013

GUARANTEES

GUARANTEES

NOTE 13 — GUARANTEES

The following table shows our outstanding guarantees:

	Total Amounts Committed at March 31, 2013		Expiration
(Millions)			Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees supporting commodity transactions of subsidiaries (1)	$	597.1	$	368.8	$	31.3	$	197.0
Standby letters of credit (2)	34.2		34.1		0.1		—
Surety bonds (3)	14.4		14.4		—		—
Other guarantees (4)	22.3		—		—		22.3
Total guarantees	$	668.0	$	417.3	$	31.4	$	219.3

⁽¹⁾  Consists of parental guarantees of $436.3 million to support the business operations of Integrys Energy Services; $108.5 million and $45.3 million, respectively, related to natural gas supply at MERC and MGU; and $5.0 million at IBS, and $2.0 million at UPPCO to support business operations. These guarantees are not reflected on our balance sheets.

⁽²⁾  At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. This amount consists of $32.5 million issued to support Integrys Energy Services’ operations and $1.7 million issued to support MERC, MGU, NSG, PGL, Pinnacle CNG Systems, UPPCO, and WPS. These amounts are not reflected on our balance sheets.

⁽³⁾  Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These guarantees are not reflected on our balance sheets.

⁽⁴⁾  Consists of (a) $10.0 million related to the sale agreement for Integrys Energy Services’ Texas retail marketing business, which included a number of customary representations, warranties, and indemnification provisions. An insignificant liability was recorded related to the possible imposition of additional miscellaneous gross receipts tax in the event of a change in law or interpretation of the tax law; (b) $5.0 million related to an environmental indemnification provided by Integrys Energy Services as part of the sale of the Stoneman generation facility, under which we expect that the likelihood of required performance is remote. This amount is not reflected on our balance sheets; and (c) $7.3 million related to other indemnifications primarily for workers compensation coverage. These amounts are not reflected on our balance sheets.

We have provided total parental guarantees of $487.0 million on behalf of Integrys Energy Services. Our exposure under these guarantees related to existing transactions at March 31, 2013, was approximately $229.7 million.