10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2012

OR

oTRANSITION 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	Internal Revenue Service Employer Identification No.
1-11337	INTEGRYS ENERGY GROUP, INC. (A Wisconsin Corporation) 130 East Randolph Street Chicago, Illinois 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 o

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 o

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 o
Non-accelerated filer o	Smaller reporting company o

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

78,287,906 shares outstanding at

April 26, 2012

INTEGRYS ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2012

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 OF Integrys Energy Group, Inc. and Subsidiaries			6 – 32
			Page
	Note 1	Financial Information	6
	Note 2	Cash and Cash Equivalents	6
	Note 3	Risk Management Activities	7
	Note 4	Discontinued Operations	11
	Note 5	Investment in ATC	11
	Note 6	Inventories	12
	Note 7	Goodwill and Other Intangible Assets	12
	Note 8	Short-Term Debt and Lines of Credit	13
	Note 9	Long-Term Debt	14
	Note 10	Income Taxes	14
	Note 11	Commitments and Contingencies	15
	Note 12	Guarantees	18
	Note 13	Employee Benefit Plans	19
	Note 14	Stock-Based Compensation	19
	Note 15	Common Equity	22
	Note 16	Variable Interest Entities	24
	Note 17	Fair Value	24
	Note 18	Advertising Costs	28
	Note 19	Regulatory Environment	28
	Note 20	Segments of Business	30
	Note 21	New Accounting Pronouncements	31
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			33 - 46
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk			47
ITEM 4.	Controls and Procedures			48
PART II.	OTHER INFORMATION			49
ITEM 1.	Legal Proceedings			49
ITEM 1A.	Risk Factors			49
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds			49
ITEM 6.	Exhibits			49
Signature				50
EXHIBIT INDEX				51

i

Commonly Used Acronyms in this Quarterly Report on Form 10-Q

AMRP	Accelerated Natural Gas Main Replacement Program
ASU	Accounting Standards Update
ATC	American Transmission Company LLC
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
GAAP	United States Generally Accepted Accounting Principles
IBS	Integrys Business Support, LLC
ICC	Illinois Commerce Commission
ICR	Infrastructure Cost Recovery
ITF	Integrys Transportation Fuels, LLC
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 Utility 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, but rather are subject to numerous management assumptions, risks, and uncertainties. Therefore, actual results may differ materially from those expressed or implied by these statements. 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, 2011, 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 coal-fired 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, including manufactured gas plant site cleanup, third-party intervention in permitting and licensing projects, compliance with Clean Air Act requirements at generation plants, and prudence and reconciliation of costs recovered in revenues through automatic gas cost recovery mechanisms;

· 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 all of 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.

	Three Months Ended
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)	March 31
(Millions, except per share data)	2012			2011
Utility revenues	$	971.0		$	1,168.7
Nonregulated revenues	280.3			458.4
Total revenues	1,251.3			1,627.1
Utility cost of fuel, natural gas, and purchased power	472.3			660.7
Nonregulated cost of sales	275.3			404.0
Operating and maintenance expense	261.0			264.6
Depreciation and amortization expense	62.7			62.3
Taxes other than income taxes	28.4			26.8
Operating income	151.6			208.7
Earnings in equity method investments	21.1			19.4
Miscellaneous income	2.4			1.8
Interest expense	(30.5		)	(34.8		)
Other expense	(7.0		)	(13.6		)
Income before taxes	144.6			195.1
Provision for income taxes	46.8			71.7
Net income from continuing operations	97.8			123.4
Discontinued operations, net of tax	1.9			0.1
Net income	99.7			123.5
Preferred stock dividends of subsidiary	(0.8		)	(0.8		)
Net income attributed to common shareholders	$	98.9		$	122.7
Average shares of common stock
Basic	78.6			78.3
Diluted	79.2			78.6
Earnings per common share (basic)
Net income from continuing operations	$	1.23		$	1.57
Discontinued operations, net of tax	0.03			—
Earnings per common share (basic)	$	1.26		$	1.57
Earnings per common share (diluted)
Net income from continuing operations	$	1.22		$	1.56
Discontinued operations, net of tax	0.03			—
Earnings per common share (diluted)	$	1.25		$	1.56
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.

	Three Months Ended
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)	March 31
(Millions)	2012			2011
Net income	$	99.7		$	123.5
Other comprehensive income, net of tax:
Cash flow hedges
Unrealized net losses arising during period, net of tax of $(0.2) million and $(2.4) million, respectively	(0.3		)	(4.1		)
Reclassification of net losses to net income, net of tax of $1.0 million and $5.1 million, respectively	1.5			8.4
Cash flow hedges, net	1.2			4.3
Defined benefit pension plans
Amortization of pension and other postretirement costs included in net periodic benefit cost, net of tax of $0.3 million and $0.2 million, respectively	0.3			0.2
Other comprehensive income, net of tax	1.5			4.5
Comprehensive income	101.2			128.0
Less: preferred stock dividends of subsidiary	(0.8		)	(0.8		)
Comprehensive income attributed to common shareholders	$	100.4		$	127.2

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)	2012			2011
Assets
Cash and cash equivalents	$	42.3		$	28.1
Collateral on deposit	64.2			50.9
Accounts receivable and accrued unbilled revenues, net of reserves of $43.4 and $47.1, respectively	669.7			737.7
Inventories	125.1			252.3
Assets from risk management activities	266.2			227.2
Regulatory assets	132.8			125.1
Deferred income taxes	101.6			94.2
Prepaid taxes	144.3			209.6
Other current assets	87.5			78.2
Current assets	1,633.7			1,803.3
Property, plant, and equipment, net of accumulated depreciation of $3,057.7 and $3,018.7, respectively	5,259.0			5,199.1
Regulatory assets	1,655.4			1,658.5
Assets from risk management activities	56.6			64.4
Equity method investments	490.6			476.3
Goodwill	658.3			658.4
Other long-term assets	125.4			123.2
Total assets	$	9,879.0		$	9,983.2
Liabilities and Equity
Short-term debt	$	305.5		$	303.3
Current portion of long-term debt	272.0			250.0
Accounts payable	331.2			426.6
Liabilities from risk management activities	400.0			311.6
Accrued taxes	75.4			70.5
Regulatory liabilities	96.5			67.5
Temporary LIFO liquidation credit	36.7			—
Other current liabilities	198.1			217.2
Current liabilities	1,715.4			1,646.7
Long-term debt	1,850.1			1,872.0
Deferred income taxes	1,108.7			1,070.7
Deferred investment tax credits	43.7			44.0
Regulatory liabilities	334.2			332.5
Environmental remediation liabilities	609.5			615.1
Pension and other postretirement benefit obligations	514.0			749.3
Liabilities from risk management activities	109.9			102.0
Asset retirement obligations	402.3			397.2
Other long-term liabilities	144.0			141.1
Long-term liabilities	5,116.4			5,323.9
Commitments and contingencies
Common stock - $1 par value; 200,000,000 shares authorized; 78,287,906 shares issued; 77,916,543 shares outstanding	78.3			78.3
Additional paid-in capital	2,566.5			2,579.1
Retained earnings	409.2			363.6
Accumulated other comprehensive loss	(41.0		)	(42.5		)
Shares in deferred compensation trust	(17.0		)	(17.1		)
Total common shareholders’ equity	2,996.0			2,961.4
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	$	9,879.0		$	9,983.2

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

4

INTEGRYS ENERGY GROUP, INC.

	Three Months Ended
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	March 31
(Millions)	2012			2011
Operating Activities
Net income	$	99.7		$	123.5
Adjustments to reconcile net income to net cash provided by operating activities
Discontinued operations, net of tax	(1.9		)	(0.1		)
Depreciation and amortization expense	62.7			62.3
Recoveries and refunds of regulatory assets and liabilities	9.5			13.5
Net unrealized losses on nonregulated energy contracts	44.7			0.7
Bad debt expense	10.1			11.5
Pension and other postretirement expense	17.6			21.1
Pension and other postretirement contributions	(246.6		)	(106.4		)
Deferred income taxes and investment tax credits	30.0			67.2
Gain on sale of assets	(0.2		)	(0.1		)
Equity income, net of dividends	(3.8		)	(3.0		)
Other	2.6			10.2
Changes in working capital
Collateral on deposit	(13.7		)	(5.2		)
Accounts receivable and accrued unbilled revenues	49.9			(50.1		)
Inventories	132.7			152.7
Other current assets	54.5			28.3
Accounts payable	(77.4		)	(23.8		)
Temporary LIFO liquidation credit	36.7			119.2
Other current liabilities	18.7			(26.0		)
Net cash provided by operating activities	225.8			395.5
Investing Activities
Capital expenditures	(123.0		)	(51.2		)
Proceeds from the sale or disposal of assets	1.4			1.1
Capital contributions to equity method investments	(10.4		)	(6.2		)
Other	(4.7		)	0.1
Net cash used for investing activities	(136.7		)	(56.2		)
Financing Activities
Short-term debt, net	2.2			57.9
Repayment of long-term debt	—			(325.0		)
Payment of dividends
Preferred stock of subsidiary	(0.8		)	(0.8		)
Common stock	(53.0		)	(47.4		)
Issuance of common stock	—			7.2
Payments made on derivative contracts related to divestitures classified as financing activities	(9.0		)	(11.1		)
Other	(14.3		)	(3.8		)
Net cash used for financing activities	(74.9		)	(323.0		)
Net change in cash and cash equivalents	14.2			16.3
Cash and cash equivalents at beginning of period	28.1			179.0
Cash and cash equivalents at end of period	$	42.3		$	195.3

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, 2012

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, 2011.

In management’s opinion, these unaudited financial statements include all adjustments considered 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 supplemental disclosure to our statements of cash flows:

	Three Months Ended March 31
(Millions)	2012			2011
Cash paid for interest	$	8.9		$	20.1
Cash (received) paid for income taxes	(33.2		)	2.9

Significant noncash transactions were:

	Three Months Ended March 31
(Millions)	2012		2011
Construction costs funded through accounts payable	$	50.2	$	9.4
Equity issued for stock-based compensation plans	—		6.6
Equity issued for reinvested dividends	—		5.4

6

NOTE 3—RISK MANAGEMENT ACTIVITIES

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

	March 31, 2012
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Utility Segments
Non-hedge derivatives
Natural gas contracts	Current	$	5.2	$	43.9
Natural gas contracts	Long-term	0.3		9.2
Financial transmission rights (FTRs)	Current	1.0		0.1
Petroleum product contracts	Current	0.4		—
Coal contract	Current	—		5.6
Coal contract	Long-term	—		7.8
Cash flow hedges
Natural gas contracts	Current	—		1.2
Natural gas contracts	Long-term	—		0.2
Nonregulated Segments
Non-hedge derivatives
Natural gas contracts	Current	121.2		120.4
Natural gas contracts	Long-term	22.3		20.7
Electric contracts	Current	138.2		228.6
Electric contracts	Long-term	34.0		72.0
Foreign exchange contracts	Current	0.2		0.2
	Current	266.2		400.0
	Long-term	56.6		109.9
Total		$	322.8	$	509.9

*All derivatives are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and sales exception. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

7

		December 31, 2011
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Utility Segments
Non-hedge derivatives
Natural gas contracts	Current	$	9.1	$	35.4
Natural gas contracts	Long-term	0.1		8.2
FTRs	Current	2.3		0.1
Petroleum product contracts	Current	0.1		—
Coal contract	Current	—		2.5
Coal contract	Long-term	—		4.4
Cash flow hedges
Natural gas contracts	Current	—		0.9
Natural gas contracts	Long-term	—		0.2
Nonregulated Segments
Non-hedge derivatives
Natural gas contracts	Current	121.6		120.5
Natural gas contracts	Long-term	41.9		40.5
Electric contracts	Current	93.9		152.0
Electric contracts	Long-term	22.4		48.7
Foreign exchange contracts	Current	0.2		0.2
	Current	227.2		311.6
	Long-term	64.4		102.0
Total		$	291.6	$	413.6

*All derivatives are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and sales exception. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

The following table shows our cash collateral positions:

(Millions)	March 31, 2012		December 31, 2011
Cash collateral provided to others	$	64.2	$	50.9
Cash collateral received from others *	1.8		2.3

*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, 2012		December 31, 2011
Integrys Energy Services	$	231.4	$	193.8
Utility segments	52.9		39.1

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, 2012		December 31, 2011
Collateral that would have been required:
Integrys Energy Services	$	281.7	$	272.3
Utility segments	42.5		28.7
Collateral already satisfied:
Integrys Energy Services — Letters of credit	11.0		11.0
Collateral remaining:
Integrys Energy Services	270.7		261.3
Utility segments	42.5		28.7

8

Utility Segments

Non-Hedge Derivatives

Utility derivatives include natural gas purchase contracts, a coal purchase contract, 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 non-hedge derivative contracts:

	March 31, 2012			December 31, 2011
	Purchases	Sales	Other Transactions	Purchases	Other Transactions
Natural gas (millions of therms)	755.5	0.3	N/A	1,122.7	N/A
FTRs (millions of kilowatt-hours)	N/A	N/A	1,911.0	N/A	5,077.5
Petroleum products (barrels)	51,872.0	N/A	N/A	46,872.0	N/A
Coal contract (millions of tons)	3.9	N/A	N/A	4.1	N/A

The tables below show the unrealized gains (losses) recorded related to non-hedge derivatives at the utilities:

		Three Months Ended March 31
(Millions)	Financial Statement Presentation	2012			2011
Natural gas contracts	Balance Sheet — Regulatory assets (current)	$	(6.4	)	$	11.2
Natural gas contracts	Balance Sheet — Regulatory assets (long-term)	(0.8		)	1.6
Natural gas contracts	Balance Sheet — Regulatory liabilities (current)	(3.7		)	(0.1		)
Natural gas contracts	Balance Sheet — Regulatory liabilities (long-term)	0.1			0.1
Natural gas contracts	Income Statement — Utility cost of fuel, natural gas, and purchased power	0.1			0.1
FTRs	Balance Sheet — Regulatory assets (current)	0.4			0.1
FTRs	Balance Sheet — Regulatory liabilities (current)	(0.3		)	(1.2		)
Petroleum product contracts	Balance Sheet — Regulatory assets (current)	0.1			—
Petroleum product contracts	Balance Sheet — Regulatory liabilities (current)	0.1			0.4
Petroleum product contracts	Income Statement — Operating and maintenance expense	0.1			0.5
Coal contract	Balance Sheet — Regulatory assets (current)	(3.1		)	(0.5		)
Coal contract	Balance Sheet — Regulatory assets (long-term)	(3.5		)	(3.2		)
Coal contract	Balance Sheet — Regulatory liabilities (long-term)	—			(3.7		)

Nonregulated Segments

Non-Hedge 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.

In the next 12 months, pre-tax losses of $0.9 million and $4.5 million related to the 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.

Integrys Energy Services had the following notional volumes of outstanding non-hedge derivative contracts:

	March 31, 2012		December 31, 2011
(Millions)	Purchases	Sales	Purchases	Sales
Commodity contracts
Natural gas (therms)	885.3	713.3	959.2	797.1
Electric (kilowatt-hours)	38,083.7	23,063.4	34,405.7	20,374.0
Foreign exchange contracts (Canadian dollars)	2.6	2.6	4.2	4.2

9

Gains (losses) related to non-hedge derivatives are recognized currently in earnings, as shown in the tables below:

		Three Months Ended March 31
(Millions)	Income Statement Presentation	2012			2011
Natural gas contracts	Nonregulated revenue	$	4.0		$	8.1
Natural gas contracts	Nonregulated revenue (reclassified from accumulated OCI) *	(1.2		)	(0.3		)
Electric contracts	Nonregulated revenue	(68.6		)	(1.0		)
Electric contracts	Nonregulated revenue (reclassified from accumulated OCI) *	(0.7		)	0.2
Total		$	(66.5	)	$	7.0

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

Fair Value Hedges

At PELLC, an interest rate swap designated as a fair value hedge was used to hedge changes in the fair value of $50.0 million of the $325.0 million Series A 6.9% notes. The interest rate swap and the notes were settled in January 2011. The changes in the fair value of this hedge were recognized in earnings, as were the changes in fair value of the hedged item. Unrealized gains (losses) related to the fair value hedge and the related hedged item are shown in the table below:

		Three Months Ended
(Millions)	Income Statement Presentation	March 31, 2011
Interest rate swap	Interest expense	$	(0.9	)
Debt hedged by swap	Interest expense	0.9
Total		$	—

Cash Flow Hedges

Prior to July 1, 2011, Integrys Energy Services designated derivative contracts such as futures, forwards, and swaps as accounting hedges under GAAP. These contracts are used to manage commodity price risk associated with customer contracts.

The tables below show the amounts related to cash flow hedges recorded in OCI and in earnings:

Unrealized Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
(Millions)	Three Months Ended March 31, 2011
Natural gas contracts	$	1.2
Electric contracts	(4.6		)
Total	$	(3.4	)

Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
		Three Months Ended March 31
(Millions)	Income Statement Presentation	2012			2011
Settled/Realized
Natural gas contracts	Nonregulated revenue	$	—		$	(8.6	)
Electric contracts	Nonregulated revenue	—			(4.1		)
Interest rate swaps *	Interest expense	(0.3		)	(0.3		)
Hedge Designation Discontinued
Natural gas contracts	Nonregulated revenue	—			(0.3		)
Total		$	(0.3	)	$	(13.3	)

*In May 2010, we entered into interest rate swaps that were designated as cash flow hedges to hedge the variability in forecasted interest payments on a debt issuance. These swaps were terminated when the related debt was issued in November 2010. Amounts remaining in accumulated OCI are being reclassified to interest expense over the life of the related debt.

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Gain Recognized in Income on Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing)
(Millions)	Income Statement Presentation	Three Months Ended March 31, 2011
Natural gas contracts	Nonregulated revenue	$	0.8
Electric contracts	Nonregulated revenue	0.3
Total		$	1.1

NOTE 4—DISCONTINUED OPERATIONS

Holding Company and Other Segment

During the three-month period ended March 31, 2012, we recorded a $1.9 million after-tax gain in discontinued operations at the holding company and other segment when we remeasured an unrecognized tax benefit liability that better reflects how the underlying uncertain tax positions are resolving themselves in various taxing jurisdictions.

Integrys Energy Services

During the three-month period ended March 31, 2011, Integrys Energy Services recorded a $0.1 million after-tax gain in discontinued operations when contingent payments were earned related to the 2009 sale of its energy management consulting business.

NOTE 5—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, 2012. ATC is a for-profit, transmission-only company regulated by FERC. ATC owns, maintains, monitors, and operates electric transmission assets in portions of Wisconsin, Michigan, Minnesota, and Illinois.

The following table shows changes to our investment in ATC.

	Three Months Ended March 31
(Millions)	2012		2011
Balance at the beginning of period	$	439.4	$	416.3
Add: Equity in net income	20.8		19.2
Add: Capital contributions	3.4		3.4
Less: Dividends received	16.7		16.2
Balance at the end of period	$	446.9	$	422.7

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

	Three Months Ended March 31
(Millions)	2012		2011
Income statement data
Revenues	$	147.7	$	139.6
Operating expenses	69.6		63.1
Other expense	20.0		22.3
Net income *	$	58.1	$	54.2

*As most income taxes are the responsibility of its members, ATC does not report a provision for its members’ income taxes in its income statements.

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(Millions)	March 31, 2012		December 31, 2011
Balance sheet data
Current assets	$	57.1	$	58.7
Noncurrent assets	3,099.0		3,053.7
Total assets	$	3,156.1	$	3,112.4
Current liabilities	$	314.5	$	298.5
Long-term debt	1,400.0		1,400.0
Other noncurrent liabilities	88.1		82.6
Members’ equity	1,353.5		1,331.3
Total liabilities and members’ equity	$	3,156.1	$	3,112.4

NOTE 6—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. Due to seasonality requirements, PGL and NSG expect interim reductions in LIFO layers to be replenished by year end.

NOTE 7—GOODWILL AND OTHER INTANGIBLE ASSETS

We had no material changes to the carrying amount of goodwill during the three months ended March 31, 2012, and 2011.

The identifiable intangible assets other than goodwill listed below are part of other current and long-term assets on the Balance Sheets.

(Millions)	March 31, 2012							December 31, 2011
	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets
Customer-related (1)	$	34.5	$	(25.4	)	$	9.1	$	34.5	$	(24.8	)	$	9.7
Electric contract assets (2)	—		—			—		7.8		(6.6		)	1.2
Patents (3)	7.2		(0.1		)	7.1		7.2		—			7.2
Compressed natural gas fueling contract assets (4)	5.6		(0.6		)	5.0		5.6		(0.3		)	5.3
Renewable energy credits (5)	3.3		—			3.3		2.8		—			2.8
Nonregulated easements (6)	3.8		(0.7		)	3.1		3.8		(0.7		)	3.1
Customer-owned equipment modifications (7)	3.8		(0.3		)	3.5		3.6		(0.2		)	3.4
Emission allowances (8)	1.6		(0.1		)	1.5		1.7		(0.2		)	1.5
Other	0.8		(0.3		)	0.5		1.4		(0.3		)	1.1
Total	$	60.6	$	(27.5	)	$	33.1	$	68.4	$	(33.1	)	$	35.3
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	$	70.8	$	(27.5	)	$	43.3	$	78.6	$	(33.1	)	$	45.5

(1)Includes customer relationship assets associated with PELLC’s former nonregulated retail natural gas and electric operations, MERC’s nonutility ServiceChoice business, 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, 2012, was approximately 10 years.

(2)Represents electric customer contracts acquired in exchange for risk management assets.

(3)Includes the fair value of patents at Pinnacle related to a system for more efficiently compressing natural gas to allow for faster fueling. The remaining amortization period at March 31, 2012, was approximately 18 years.

(4)Represents the fair value of Trillium and Pinnacle compressed natural gas customer fueling contracts acquired in September 2011. The remaining amortization period at March 31, 2012, was approximately 9 years.

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(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, 2012, of approximately 12 years.

(7)Relates to modifications to customer-owned equipment that allow the end-use customer of a pipeline to accept landfill gas. These intangible assets are amortized on a straight-line basis, with a remaining weighted-average amortization period at March 31, 2012, of approximately 12 years.

(8)Emission allowances do not have a contractual term or expiration date. If the EPA’s Cross State Air Pollution Rule, which was stayed in December 2011, is reinstated, it will affect our ability to use certain existing emission allowances in the future. See Note 11, “Commitments and Contingencies,” for more information.

Amortization expense recorded as a component of nonregulated cost of sales in the statements of income for the three months ended March 31, 2012, and 2011, was $1.6 million and $0.3 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, 2012, and 2011, was $0.7 million and $0.8 million, respectively.

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

	For the year ending December 31
(Millions)	2012		2013		2014		2015		2016
Amortization recorded in nonregulated cost of sales	$	5.9	$	1.8	$	1.4	$	1.3	$	1.1
Amortization recorded in depreciation and amortization expense	2.5		2.0		1.7		1.7		1.5

NOTE 8—SHORT-TERM DEBT AND LINES OF CREDIT

Our short-term borrowings were as follows:

(Millions, except percentages)	March 31, 2012			December 31, 2011
Commercial paper outstanding	$	305.5		$	303.3
Average discount rate on outstanding commercial paper	0.34		%	0.31		%

The commercial paper outstanding at March 31, 2012, had maturity dates ranging from April 2, 2012, through April 30, 2012.

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

(Millions)	2012		2011
Average amount of commercial paper outstanding	$	357.5	$	102.7
Average amount of short-term notes payable outstanding	—		10.0

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:

(Millions)	Maturity	March 31, 2012		December 31, 2011
Revolving credit facility (Integrys Energy Group)	04/23/13	$	735.0	$	735.0
Revolving credit facility (Integrys Energy Group)	05/17/16	200.0		200.0
Revolving credit facility (Integrys Energy Group)	05/17/14	275.0		275.0
Revolving credit facility (WPS)	04/23/13	115.0		115.0
Revolving credit facility (WPS)	05/17/14	135.0		135.0
Revolving credit facility (PGL)	04/23/13	250.0		250.0
Total short-term credit capacity		$	1,710.0	$	1,710.0
Less:
Letters of credit issued inside credit facilities		$	33.9	$	33.7
Commercial paper outstanding		305.5		303.3
Available capacity under existing agreements		$	1,370.6	$	1,373.0

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NOTE 9—LONG-TERM DEBT

(Millions)	March 31, 2012			December 31, 2011
WPS (1)	$	722.1		$	722.1
PGL	525.0			525.0
NSG (2)	74.7			74.7
Integrys Energy Group (3)	774.8			774.8
Other term loan (4)	27.0			27.0
Total	2,123.6			2,123.6
Unamortized discount	(1.5		)	(1.6		)
Total debt	2,122.1			2,122.0
Less current portion	(272.0		)	(250.0		)
Total long-term debt	$	1,850.1		$	1,872.0

(1)In December 2012, WPS’s 4.875% Senior Notes will mature. As a result, the $150.0 million balance of these notes was included in current portion of long-term debt on our balance sheets.

In February 2013, WPS’s 3.95% Senior Notes will mature. As a result, the $22.0 million balance of these notes was included in current portion of long-term debt on our March 31, 2012 balance sheet.

(2)In April 2012, NSG bought back its $28.2 million of 5.00% Series M First Mortgage Bonds that were due December 1, 2028.

In the same month, NSG issued $28.0 million of 3.43% Series P First Mortgage Bonds. These bonds are due April 1, 2027.

(3)In December 2012, our 5.375% Unsecured Senior Notes will mature. As a result, the $100.0 million balance of these notes was included in current portion of long-term debt on our balance sheets.

(4)This loan has a floating interest rate that is reset weekly. At March 31, 2012, the interest rate was 0.20%. The loan is to be repaid by April 2021.

NOTE 10—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
	2012		2011
Effective Tax Rate	32.4	%	36.8	%

Our effective tax rate for the three months ended March 31, 2012, was lower than the federal statutory tax rate of 35%. This difference primarily related to the federal income tax benefit of tax credits related to wind production and a remeasurement of an unrecognized tax benefit liability that better reflects how the underlying uncertain tax positions are resolving themselves in various taxing jurisdictions. Other state income tax obligations partially offset the lower effective tax rate.

Our effective tax rate for the three months ended March 31, 2011, was higher than the federal statutory tax rate of 35%. This difference primarily related to state income tax obligations, partially offset by tax credits related to wind production, along with other tax credits.

During the three months ended March 31, 2012, we remeasured and decreased our liability for unrecognized tax benefits by $2.7 million that  better reflects how the underlying uncertain tax positions are resolving themselves in various taxing jurisdictions. We reduced the provision for income taxes related to this remeasurement, of which a portion was reported as discontinued operations.

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NOTE 11—COMMITMENTS AND CONTINGENCIES

Commodity 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 purchase obligations described below were as of March 31, 2012.

· The electric utility segment had obligations of $186.3 million related to coal supply and transportation that extend through 2016, obligations of $1,213.9 million for either capacity or energy related to purchased power that extend through 2029, and obligations of $5.4 million for other commodities that extend through 2013.

· The natural gas utility segment had obligations of $836.7 million related to natural gas supply and transportation contracts that extend through 2028.

· Integrys Energy Services had obligations of $218.9 million, primarily related to electricity and natural gas supply contracts that extend through 2021.

· We and our subsidiaries also had commitments of $536.1 million in the form of purchase orders issued to various vendors that relate to normal business operations, including construction projects.

Environmental

Clean Air Act (CAA) New Source Review Issues

Weston and Pulliam Plants:

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 continues to meet with the EPA and exchange proposals on a possible resolution. We are currently unable to estimate the possible loss or range of loss related to this matter.

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. WPS is working on a possible resolution with the Sierra Club and the EPA. We are currently unable to estimate the possible loss or range of loss related to this matter.

Columbia and Edgewater Plants:

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 WPS). The NOV alleges violations of the CAA’s New Source Review requirements related to certain projects completed at those plants. WP&L and the other joint owners exchanged proposals with the EPA on a possible resolution. We are currently unable to estimate the possible loss or range of loss related to this matter.

In September 2010, the Sierra Club filed a lawsuit against WP&L, which included allegations that modifications made at the Columbia plant did not comply with the CAA. While the previous stay has been lifted and the case is moving forward to a December 2012 trial, the Sierra Club continues to participate in settlement negotiations with the EPA and the joint owners of the Columbia plant to seek resolution. We are currently unable to estimate the possible loss or range of loss related to this matter.

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. The previous stay of this case has been extended until July 15, 2012, and settlement negotiations with the Sierra Club, the EPA, and the joint owners of the Edgewater plant continue. We are currently unable to estimate the possible loss or range of loss related to this matter.

EPA Settlements with Other Utilities:

In response to the EPA’s CAA enforcement initiative, several utilities elected to settle with the EPA, while others are in litigation. The fines, penalties, and costs of supplemental beneficial environmental projects associated with settlements involving comparably-sized facilities to Weston and Pulliam combined ranged between $6 million and $30 million. The regulatory interpretations upon which the lawsuits or settlements are based may change depending on future court decisions made in the pending litigation.

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If it were settled or determined that historical projects at the Weston, Pulliam, Columbia, and Edgewater plants required either a state or federal CAA permit, WPS may, under the applicable statutes, be required to complete the following remedial steps:

· shut down the facility,

· install additional pollution control equipment and/or impose emission limitations, and/or

· conduct a supplemental beneficial environmental project.

In addition, WPS may also be required to pay a fine. Finally, under the CAA, citizen groups may pursue a claim.

Weston Air Permits

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, the WDNR, WPS, 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 and the Sierra Club to resolve this issue. We do not expect this matter to have a material impact on our financial statements.

Weston Title V Air Permit:

In November 2010, the WDNR provided a draft revised permit. WPS objected to proposed changes in mercury limits and requirements on the boilers as beyond the authority of the WDNR. WPS and the WDNR continue to meet to resolve these issues. In September 2011, the WDNR issued a draft revised permit and a request for public comments. WPS filed comments objecting to certain provisions in the draft permit. We do not expect this matter to have a material impact on our financial statements.

WDNR Issued NOVs:

Since 2008, WPS received four NOVs from the WDNR alleging various violations of the different air permits for the entire Weston plant, Weston 4, Weston 1, and Weston 2, as well as one 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 dismissed two of the NOVs and referred the other three NOVs to the state Justice Department for enforcement. We do not expect this matter to have a material impact on our financial statements.

Pulliam Title V Air Permit

The WDNR issued the 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 objecting to this permit.

WPS also challenged the permit in a contested case proceeding and Petition for Judicial Review. The Petition was dismissed in an order remanding the matter to the WDNR. In February 2011, the WDNR granted a contested case proceeding before an Administrative Law Judge on the issues raised by WPS, which included averaging times in the emission limits in the permit. WPS participated in the contested case proceeding in October 2011. In December 2011, the Administrative Law Judge did not require the WDNR to insert averaging times, for which WPS had argued. WPS has decided not to appeal.

In October 2010, WPS received from the Sierra Club a copy of an NOI to file a civil lawsuit against the EPA based on what the Sierra Club alleges to be the EPA’s unreasonable delay in performing its duties related to the grant or denial of the permit. WPS received notification that the Sierra Club filed suit against the EPA in April 2011. WPS intervened in the case as a necessary party to protect its interests. The WDNR sent the proposed permit to the EPA for a 45-day review, which allowed the parties to enter into a settlement agreement that has not yet been entered by the court.

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 October 2009, the EPA issued an order objecting to the permit renewal issued by the WDNR for the Columbia plant. The order determined that the WDNR did not adequately analyze whether a project in 2006 constituted a “major modification that required a permit.”  The EPA’s order directed the WDNR to resolve the objections within 90 days and “terminate, modify, or revoke and reissue” the permit accordingly.

In July 2010, WPS, along with its co-owners, received from the Sierra Club a copy of an NOI to file a civil lawsuit against the EPA. The Sierra Club alleges that the EPA should assert jurisdiction over the permit because the WDNR failed to respond to the EPA’s objection within 90 days.

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In September 2010, the WDNR issued a draft construction permit and a draft revised Title V permit in response to the EPA’s order. In November 2010, the EPA notified the WDNR that the EPA “does not believe the WDNR’s proposal is responsive to the order.”  In January 2011, the WDNR issued a letter stating that upon review of the submitted public comments, the WDNR has determined not to issue the draft permits that were proposed to respond to the EPA’s order. In February 2011, the Sierra Club filed for a declaratory action, claiming that the EPA had to assert jurisdiction over the permits. In May 2011, the WDNR issued a second draft Title V permit in response to the EPA’s order. WPS is monitoring this situation with WP&L and meeting with the WDNR. 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, Chapter NR 446, requires a 40% reduction from the 2002 through 2004 baseline mercury emissions in Phase I, beginning January 1, 2010, through the end of 2014. In Phase II, which begins in 2015, electric generating units above 150 megawatts will be required to reduce mercury emissions by 90%. 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, 2012, WPS estimates capital costs of approximately $2 million, which includes estimates for both wholly owned and jointly owned plants, to achieve the required Phase I and Phase II reductions. The capital costs are expected to be recovered in future rate cases.

In December 2011, the EPA issued the final Utility Mercury and Air Toxics rule that will regulate emissions of mercury and other hazardous air pollutants. 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:

The EPA issued the Clean Air Interstate Rule (CAIR) in 2005 in order to reduce sulfur dioxide and nitrogen oxide emissions from utility boilers located in 29 states, including Wisconsin, Michigan, Pennsylvania, and New York. In July 2008, the United States Court of Appeals (Court of Appeals) issued a decision vacating CAIR, which the EPA appealed. In December 2008, the Court of Appeals reinstated CAIR and directed the EPA to address the deficiencies noted in its previous ruling to vacate CAIR. In July 2011, the EPA issued a final CAIR replacement rule known as the Cross State Air Pollution Rule (CSAPR). The new rule was to become effective January 1, 2012; however, on December 30, 2011, the D.C. Circuit Court (Court) issued a decision that stayed the rule pending the Court’s resolution of the petitions for review. The Court directed the EPA to implement CAIR during the stay period. In January 2012, a briefing and oral argument schedule was set. Oral arguments were held on April 13, 2012. In comparison to the CAIR rule, CSAPR, in the version that was stayed, significantly reduced the emission allowances allocated to our subsidiaries’ existing units for sulfur dioxide and nitrogen oxide in 2012, with a further reduction in 2014.

CSAPR also established new sulfur dioxide and nitrogen oxide emission allowances and did not allow carryover of the existing nitrogen oxide emission allowances allocated to WPS under CAIR. WPS did not acquire any CAIR nitrogen oxide emission allowances for 2012 and beyond other than those directly allocated to it, which were free. Sulfur dioxide emission allowances allocated under the Acid Rain Program will continue to be issued and surrendered independent of the stayed CSAPR emission allowance program. Thus, we do not expect any material impact on our financial statements as a result of being unable to carry over existing emission allowances.

Under CAIR, units affected by the Best Available Retrofit Technology (BART) rule are considered in compliance with BART for sulfur dioxide and nitrogen oxide emissions if they are in compliance with 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. The EPA has proposed that units in compliance with CSAPR, if the stay is lifted and CSAPR is reinstated, will also be considered in compliance with BART.

The Court may uphold CSAPR, invalidate CSAPR, or direct the EPA to make changes to CSAPR. In order to be in compliance with the stayed version of CSAPR, additional sulfur dioxide and nitrogen oxide controls would need to be installed, emission allowances would need to be purchased, and/or our subsidiaries would have to make other changes to how they operate their existing units. The installation of any necessary controls will be scheduled as part of WPS’s long-term maintenance plan for its existing units; however, WPS does not currently believe it could meet the stayed CSAPR’s sulfur dioxide and nitrogen oxide emission limits without purchasing additional emission allowances or changing how its existing units are operated. Due to the uncertainty surrounding the rule, we are currently unable to predict whether, or if, additional emission allowances would be available to purchase or how much it would cost to comply. We are also currently unable to predict whether CSAPR, or any future version of CSAPR, will cause WPS to idle or abandon certain units or impact the estimated useful lives of certain units. WPS expects to recover any future compliance costs in future rates. The 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

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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, 2012, we estimated and accrued for $608.1 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, 2012, cash expenditures for environmental remediation not yet recovered in rates were $15.6 million. We recorded a regulatory asset of $623.7 million at March 31, 2012, which is net of insurance recoveries received of $59.9 million, related to the expected recovery of both cash expenditures and estimated future expenditures through rates.

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 WPS, MGU, PGL, and NSG. 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 rate recovery of such costs.

NOTE 12—GUARANTEES

The following table shows our outstanding guarantees:

	Total Amounts		Expiration
(Millions)	Committed at March 31, 2012		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees supporting commodity transactions of subsidiaries (1)	$	623.9	$	407.7	$	6.9	$	209.3
Standby letters of credit (2)	66.9		35.3		31.5		0.1
Surety bonds (3)	13.8		13.8		—		—
Other guarantees (4)	42.6		20.0		—		22.6
Total guarantees	$	747.2	$	476.8	$	38.4	$	232.0

(1)Consists of parental guarantees of $456.2 million to support the business operations of Integrys Energy Services; $111.8 million and $48.9 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 $64.1 million issued to support Integrys Energy Services’ operations and $2.8 million issued to support UPPCO, WPS, MGU, NSG, MERC, PGL, and Pinnacle CNG Systems. 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) $20.0 million related to the sale agreement for Integrys Energy Services’ United States wholesale electric marketing and trading business, which included a number of customary representations, warranties, and indemnification provisions. In addition, for a two-year period, counterparty payment default risk was retained with approximately 50% of the counterparties associated with the commodity contracts transferred in this transaction. An insignificant liability was recorded related to the fair value of this counterparty payment default risk; (b) $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; (c) $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 the balance sheets); and (d) $7.6 million related to other indemnifications primarily for workers compensation coverage. This amount is not reflected on our balance sheets.

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We have provided total parental guarantees of $559.0 million on behalf of Integrys Energy Services as shown in the table below. Our exposure under these guarantees related to existing transactions at March 31, 2012, was approximately $319.3 million.

(Millions)	March 31, 2012
Guarantees supporting commodity transactions	$	456.2
Standby letters of credit	64.1
Surety bonds	3.2
Other	35.5
Total guarantees	$	559.0

NOTE 13—EMPLOYEE BENEFIT PLANS

As of February 16, 2012, our defined benefit pension plans were closed to all new hires.

The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheet) for our benefit plans for the three months ended March 31:

	Pension Benefits						Other Postretirement Benefits
(Millions)	2012			2011			2012			2011
Service cost	$	12.4		$	11.3		$	5.5		$	5.0
Interest cost	19.8			20.5			7.2			7.7
Expected return on plan assets	(27.1		)	(24.7		)	(7.0		)	(5.0		)
Amortization of transition obligation	—			—			0.1			0.1
Amortization of prior service cost (credit)	1.2			1.3			(0.9		)	(0.9		)
Amortization of net actuarial loss	8.3			4.7			1.6			1.1
Net periodic benefit cost	$	14.6		$	13.1		$	6.5		$	8.0

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. We contributed $171.5 million to our pension plans and $75.1 million to our other postretirement benefit plans during the three months ended March 31, 2012. We expect to contribute an additional $3.8 million to our pension plans and $39.1 million to our other postretirement benefit plans during the remainder of 2012, dependent upon various factors affecting us, including our liquidity position and tax law changes.

NOTE 14—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)	2012		2011
Performance stock rights	$	1.2	$	(0.7	)
Restricted shares and restricted share units	2.1		2.2
Total stock-based compensation expense	$	3.3	$	1.5
Deferred income tax benefit	$	1.3	$	0.6

Compensation cost recognized for stock options during the three months ended March 31, 2012, and 2011, was not significant.

The total compensation cost capitalized for all awards during the three months ended March 31, 2012, and 2011, was not significant.

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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, 2012, along with the assumptions incorporated into the valuation model:

	February 2012 Grant
Weighted-average fair value per option	$	6.30
Expected term		5 years
Risk-free interest rate		0.17% - 2.18%
Expected dividend yield		5.28%
Expected volatility		25%

A summary of stock option activity for the three months ended March 31, 2012, and information related to outstanding and exercisable stock options at March 31, 2012, 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, 2011	2,953,630		$	48.09
Granted	279,535		53.24
Exercised	(225,986	)	44.83
Outstanding at March 31, 2012	3,007,179		$	48.82	5.97	$	14.2
Exercisable at March 31, 2012	2,221,968		$	49.24	5.02	$	9.9

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, 2012. This is calculated as the difference between our closing stock price on March 31, 2012, 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, 2012, and 2011, was $2.0 million and $0.6 million, respectively.

As of March 31, 2012, $2.6 million of compensation cost related to unvested and outstanding stock options was expected to be recognized over a weighted-average period of 3.2 years.

Cash received from option exercises during the three months ended March 31, 2012 was $10.1 million, and was not significant for the three months ended March 31, 2011. The actual tax benefit realized for the tax deductions from these option exercises was not significant for the three months ended March 31, 2012, and 2011.

Performance Stock Rights

The fair values of performance stock rights were 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 was estimated using one to three years of historical data. The table below reflects the assumptions used in the valuation of the outstanding grants at March 31:

	2012
Risk-free interest rate	0.32% - 1.27%
Expected dividend yield	5.28% - 5.34%
Expected volatility	21% - 36%

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A summary of the activity for the three months ended March 31, 2012, related to performance stock rights accounted for as equity awards is presented below:

	Performance Stock Rights		Weighted-AverageFair Value*
Outstanding at December 31, 2011	135,948		$	46.18
Granted	18,865		52.70
Distributed	(70,598	)	42.93
Adjustment for final payout	(24,804	)	42.93
Outstanding at March 31, 2012	59,411		$	53.48

*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 for awards that have not been elected for deferral into the deferred compensation plan six months prior to the completion of the performance period.

A summary of the activity for the three months ended March 31, 2012, related to performance stock rights accounted for as liability awards is presented below:

	Performance Stock Rights
Outstanding at December 31, 2011	186,215
Granted	75,408
Distributed	(16,001	)
Adjustment for final payout	(5,622	)
Outstanding at March 31, 2012	240,000

The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of March 31, 2012, was $56.22 per performance stock right.

As of March 31, 2012, $5.7 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 2.3 years.

The total intrinsic value of performance stock rights distributed during the three months ended March 31, 2012, and 2011, was $4.7 million and $6.3 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, 2012, and 2011 was $1.9 million and $2.5 million, respectively.

Restricted Shares and Restricted Share Units

During the second quarter of 2011, the last of the outstanding restricted shares vested. Only restricted share units remain outstanding at March 31, 2012.

A summary of the activity related to all restricted share unit awards (equity and liability awards) for the three months ended March 31, 2012, is presented below:

	Restricted ShareUnit Awards		Weighted-AverageGrant Date Fair Value
Outstanding at December 31, 2011	497,722		$	45.21
Granted	188,346		53.24
Dividend equivalents	6,821		47.94
Vested	(193,878	)	45.07
Forfeited	(1,440	)	46.48
Outstanding at March 31, 2012	497,571		$	48.39

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As of March 31, 2012, $16.7 million of compensation cost related to these awards was expected to be recognized over a weighted-average period of 3.1 years.

The total intrinsic value of restricted share and restricted share unit awards vested for the three months ended March 31, 2012, and 2011, was $10.4 million and $6.3 million, respectively. The actual tax benefit realized for the tax deductions from the vesting of restricted shares and restricted share units during the three months ended March 31, 2012, and 2011, was $4.2 million and $2.5 million, respectively.

The weighted-average grant date fair value of restricted share units awarded during the three months ended March 31, 2012, and 2011, was $53.24 and $49.40 per share, respectively.

NOTE 15—COMMON EQUITY

We had no changes to issued common stock during the three months ended March 31, 2012.

Beginning May 1, 2011, shares were purchased on the open market to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans.

The following table reconciles common shares issued and outstanding:

	March 31, 2012				December 31, 2011
	Shares	Average Cost			Shares	Average Cost
Common stock issued	78,287,906				78,287,906
Less:
Deferred compensation rabbi trust	371,363	$	45.71	*	382,971	$	44.54	*
Total common shares outstanding	77,916,543				77,904,935

*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 calculation of diluted earnings per share for the three months ended March 31, 2012, and 2011, each excluded 0.8 million 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)	2012			2011
Numerator:
Net income from continuing operations	$	97.8		$	123.4
Discontinued operations, net of tax	1.9			0.1
Preferred stock dividends of subsidiary	(0.8		)	(0.8		)
Net income attributed to common shareholders	$	98.9		$	122.7
Denominator:
Average shares of common stock — basic	78.6			78.3
Effect of dilutive securities
Stock-based compensation	0.4			0.3
Deferred compensation	0.2			—
Average shares of common stock — diluted	79.2			78.6
Earnings per common share
Basic	$	1.26		$	1.57
Diluted	1.25			1.56

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Accumulated Other Comprehensive Loss

The following table shows the changes to our accumulated other comprehensive loss from December 31, 2011 to March 31, 2012:

	Cash Flow Hedges			Defined Benefit Pension Plans			Accumulated Other Comprehensive Income (Loss)
Beginning balance at December 31, 2011	$	(11.5	)	$	(31.0	)	$	(42.5	)
Current period other comprehensive income	1.2			0.3			1.5
Ending balance at March 31, 2012	$	(10.3	)	$	(30.7	)	$	(41.0	)

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 normal dividends on its common stock of no more than 103% of the previous year’s common stock dividend. In addition, the PSCW currently requires WPS to maintain a calendar year average financial common equity ratio of 50.24% or higher. WPS must obtain PSCW approval if the payment of dividends would cause it to fall below this authorized level of common equity. 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, 2012, these covenants did not restrict the payment of any dividends beyond the amount restricted under our subsidiary requirements described above.

As of March 31, 2012, total restricted net assets were approximately $1,410.5 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was approximately $112.5 million at March 31, 2012.

We also 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, 2012, capital transactions with subsidiaries were as follows (in millions):

Subsidiary	Dividends To Parent		Return Of Capital To Parent		Equity Contributions From Parent
WPS	$	26.4	$	—	$	40.0
WPS Investments, LLC *	16.7		—		3.4
MERC	—		15.0		—
IBS	—		3.0		—
MGU	—		6.0		—
UPPCO	—		2.5		8.5
Total	$	43.1	$	26.5	$	51.9

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*WPS Investments, LLC is a consolidated subsidiary that is jointly owned by us, WPS, and UPPCO. At March 31, 2012, WPS and UPPCO had a 12.17% and 2.59% ownership interest, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2012, all equity contributions to WPS Investments, LLC were made solely by us.

NOTE 16—VARIABLE INTEREST ENTITIES

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 will be 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, 2012, and December 31, 2011, 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 insignificant.

We have variable interests in two entities through power purchase agreements relating to the cost of fuel. One of these purchased power agreements reimburses an independent power producing entity for coal costs relating to purchased energy. There is no obligation to purchase energy under the agreement. This contract expires in 2014. The other agreement contains a tolling arrangement in which we supply the scheduled fuel and purchase capacity and energy from the facility. This contract expires in 2016. As of March 31, 2012, and December 31, 2011, we had approximately 517.5 megawatts of capacity available under these agreements. We evaluated each of these variable interest entities 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 contracts compared with the remaining lives of the plants and the fact that we do not have the power to direct the operations and maintenance of the facilities, we determined we are not the primary beneficiary of these variable interest entities. At March 31, 2012, and December 31, 2011, the assets and liabilities on the balance sheets that related to our involvement with these variable interest entities 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 these contracts. There is not a significant potential exposure to loss as a result of involvement with the variable interest entities.

NOTE 17—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, 2012
(Millions)	Level 1		Level 2		Level 3		Total
Risk Management Assets
Utility Segments
Natural gas contracts	$	—	$	5.5	$	—	$	5.5
Financial transmission rights (FTRs)	—		—		1.0		1.0
Petroleum product contracts	0.4		—		—		0.4
Nonregulated Segments
Natural gas contracts	41.5		90.9		11.1		143.5
Electric contracts	61.3		96.8		14.1		172.2
Foreign exchange contracts	—		0.2		—		0.2
Total Risk Management Assets	$	103.2	$	193.4	$	26.2	$	322.8
Risk Management Liabilities
Utility Segments
Natural gas contracts	$	1.6	$	52.9	$	—	$	54.5
FTRs	—		—		0.1		0.1
Coal contract	—		—		13.4		13.4
Nonregulated Segments
Natural gas contracts	47.7		93.2		0.2		141.1
Electric contracts	81.2		183.4		36.0		300.6
Foreign exchange contracts	0.2		—		—		0.2
Total Risk Management Liabilities	$	130.7	$	329.5	$	49.7	$	509.9

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	December 31, 2011
(Millions)	Level 1		Level 2		Level 3		Total
Risk Management Assets
Utility Segments
Natural gas contracts	$	0.1	$	9.1	$	—	$	9.2
FTRs	—		—		2.3		2.3
Petroleum product contracts	0.1		—		—		0.1
Nonregulated Segments
Natural gas contracts	50.7		104.1		8.7		163.5
Electric contracts	41.2		71.2		3.9		116.3
Foreign exchange contracts	—		0.2		—		0.2
Total Risk Management Assets	$	92.1	$	184.6	$	14.9	$	291.6
Risk Management Liabilities
Utility Segments
Natural gas contracts	$	5.5	$	39.2	$	—	$	44.7
FTRs	—		—		0.1		0.1
Coal contract	—		—		6.9		6.9
Nonregulated Segments
Natural gas contracts	55.0		105.6		0.4		161.0
Electric contracts	54.2		131.1		15.4		200.7
Foreign exchange contracts	0.2		—		—		0.2
Total Risk Management Liabilities	$	114.9	$	275.9	$	22.8	$	413.6

The risk management assets and liabilities listed in the tables 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 — Electric Contracts

	Three Months Ended March 31, 2012								Three Months Ended March 31, 2011
(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			(0.1		)	$	—	N/A			(2.4		)
Transfers into Level 3 from	—		(5.0		)	N/A			—		(5.4		)	N/A

Nonregulated Segments — Natural Gas Contracts

	Three Months Ended March 31, 2012						Three Months Ended March 31, 2011
(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		1.3		$	—	N/A			0.4
Transfers into Level 3 from	—		2.4		N/A		—		(0.1		)	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. We recognize transfers between the levels of the fair value hierarchy at the value as of the end of the reporting period.

We determine fair value using a market-based approach that uses observable market inputs where available, and internally developed inputs where observable market data is not readily available. For the unobservable inputs, consideration is given to the assumptions that market participants would use in valuing the asset or liability. These factors include not only the credit standing of the counterparties involved, but also the impact of our nonperformance risk on our liabilities.

When possible, we base the valuations of our risk management assets and liabilities on quoted prices for identical assets in active markets. These valuations are classified in Level 1. The valuations of certain contracts include inputs related to market price risk (commodity or interest rate), price volatility (for option contracts), price correlation (for cross commodity contracts), probability of default, and time value. These inputs are available through multiple sources, including brokers and over-the-counter and online exchanges. Transactions valued using these inputs are classified in Level 2.

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Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows:

·While forward price curves may have been based on observable information, significant assumptions may have been made regarding monthly shaping and locational basis differentials.

·Certain transactions were valued using price curves that extended beyond an observable period. Assumptions were made to extrapolate prices from the last observable period through the end of the transaction term, primarily through the use of historically settled data or correlations to other locations.

We conduct a thorough review of fair value hierarchy classifications on a quarterly basis.

We have established risk oversight committees whose primary responsibility includes directly or indirectly ensuring that all valuation methods are applied in accordance with predefined policies. The development and maintenance of our forward price curves has been assigned to our risk management department, which is part of the corporate treasury function. This group is separate and distinct from any of the trading functions within the organization. To validate the reasonableness of our fair value inputs, our risk management department compares changes in valuation and researches any significant differences in order to determine the underlying cause. Corrections to the fair value inputs are made if necessary.

The significant unobservable inputs used in the valuation that resulted in categorization within Level 3 were as follows at March 31, 2012. 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 ($/megawatt-month) (1)	170.36
Coal contract	—		13.4		Market-based	Forward market prices ($/ton) (2)	14.6 –15.1
Nonregulated Segments
Natural gas contracts	11.1		0.2		Market-based	Forward market prices ($/dekatherm) (3)	(0.04) –1.54
						Probability of default	11.62% - 50.99%
Electric contracts	14.1		36.0		Market-based	Forward market prices ($/megawatt-hours) (3)	(6.05) - 9.79
						Option volatilities (4)	19.99% - 59.51%
						Monthly curve shaping (5)	(15.03)% - (11.57)%

(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 contract.
(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.
(5)	Represents adjustments made to forward market price curves to disaggregate average prices of multiple periods into discrete monthly prices.

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.

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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, 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 (losses) gains 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	)

Three Months Ended March 31, 2011	Nonregulated Segments						Utility Segments
(Millions)	Natural Gas			Electric			FTRs			Coal Contract			Total
Balance at the beginning of the period	$	30.2		$	(14.9	)	$	2.9		$	2.5		$	20.7
Net realized and unrealized gains (losses) included in earnings	4.0			(2.9		)	0.1			—			1.2
Net unrealized losses recorded as regulatory assets or liabilities	—			—			(1.1		)	(7.0		)	(8.1		)
Net unrealized losses included in other comprehensive loss	—			(0.7		)	—			—			(0.7		)
Purchases	—			0.3			—			—			0.3
Sales	—			—			(0.1		)	—			(0.1		)
Settlements	(15.2		)	2.5			(0.8		)	(0.4		)	(13.9		)
Net transfers into Level 3	(0.1		)	(5.4		)	—			—			(5.5		)
Net transfers out of Level 3	(0.4		)	2.4			—			—			2.0
Balance at the end of the period	$	18.5		$	(18.7	)	$	1.0		$	(4.9	)	$	(4.1	)
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	$	4.0		$	(2.9	)	$	—		$	—		$	1.1

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, 2012				December 31, 2011
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	2,122.1	$	2,272.2	$	2,122.0	$	2,281.5
Preferred stock	51.1		50.9		51.1		51.8

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, without considering the effect of third-party credit enhancements. 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.

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NOTE 18—ADVERTISING COSTS

At March 31, 2012, 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. The asset balances for each of the direct-response advertising cost pools are reviewed quarterly for impairment. Capitalized direct-response advertising costs, net of accumulated amortization, totaled $4.4 million as of March 31, 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 $1.0 million for the quarter ended March 31, 2012. There was no amortization of direct-response advertising costs for the quarter ended March 31, 2011.

We expense all advertising costs as incurred, except for those capitalized as direct-response advertising. Other advertising expense was $1.7 million and $1.9 million for the quarters ended March 31, 2012 and 2011, respectively.

NOTE 19—REGULATORY ENVIRONMENT

Wisconsin

2013 Rate Case

On March 30, 2012, WPS filed an application with the PSCW to increase retail electric and natural gas rates $85.1 million and $12.8 million, respectively, with rates proposed to be effective January 1, 2013. The filing includes a request for a 10.30% return on common equity and a common equity ratio of 52.37% in WPS’s regulatory capital structure. The proposed retail electric and natural gas rate increases for 2013 are primarily being driven by reduced sales, increased fuel costs to generate electricity, increased electric transmission costs, increased costs to maintain the integrity of natural gas pipelines, increased manufactured gas plant cleanup costs, and general inflation.

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 exceed a 2% price variance from costs included in rates, they will be deferred for recovery or refund in a future rate proceeding. The rate order allows for the netting of the 2010 electric decoupling under-collection with the 2011 electric decoupling over-collection, and reflects reduced contributions to the Focus on Energy Program. The rate order also allows for the deferral of direct Cross State Air Pollution Rule (CSAPR) compliance costs, including carrying costs. As of March 31, 2012, WPS deferred $1.3 million of costs related to CSAPR.

2011 Rates

On January 13, 2011, the PSCW issued a final written order for WPS authorizing an electric rate increase of $21.0 million, calculated on a per unit basis. Although the rate order included a lower authorized return on common equity, lower rate base, and other reduced costs, which resulted in lower total revenues and margins, the rate order also projected lower total sales volumes, which led to a rate increase on a per-unit basis. The rate order also included a projected increase in customer counts that did not materialize, which impacts the decoupling calculation as it adjusts for differences between the actual and authorized margin per customer. The $21.0 million electric rate increase included $20.0 million of recovery of prior deferrals, the majority of which related to the recovery of the 2009 electric decoupling deferral. The $21.0 million excluded the impact of a $15.2 million estimated fuel refund (including carrying costs) from 2010. The PSCW rate order also required an $8.3 million decrease in natural gas rates, which included $7.1 million of recovery for the 2009 decoupling deferral. The new rates were effective January 14, 2011, and reflected a 10.30% return on common equity, down from a 10.90% return on common equity in the previous rate order, and a common equity ratio of 51.65% in WPS’s regulatory capital structure.

The order also addressed the new Wisconsin electric fuel rule, which was finalized on March 1, 2011. The new fuel rule was effective retroactive to January 1, 2011. It requires the deferral of under or over-collections of fuel and purchased power costs that exceed a 2% price variance from the cost of fuel and purchased power included in rates. Under or over-collections deferred in the current year will be recovered or refunded in a future rate proceeding.

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Michigan

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 settlement required UPPCO to terminate its existing decoupling mechanism, effective December 31, 2011. Additionally, the settlement agreement 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. 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. 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. It is unknown at this time whether the ruling will be appealed.

2011 UPPCO Rates

On December 21, 2010, the MPSC issued an order approving a settlement agreement for UPPCO authorizing a retail electric rate increase of $8.9 million, effective January 1, 2011. The new rates reflected a 10.30% return on common equity and a common equity ratio of 54.86% in UPPCO’s regulatory capital structure. The order required UPPCO to terminate its uncollectibles expense tracking mechanism after the close of December 2010 business, but retained the decoupling mechanism.

Illinois

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 reflect 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 reflect 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. On February 23, 2012, the ICC rejected the rehearing requests filed by PGL, NSG, and certain interveners. Two interveners, including the Illinois Attorney General, filed appeals of the rate order, including the permanent decoupling mechanism.

The Illinois Attorney General filed a motion with the ICC to stay the implementation of the permanent decoupling mechanism or, in the alternative, make collections subject to refund. The ICC denied the motion. However, the ICC issued an amendatory order with unclear language directing PGL and NSG to identify funds, which would be due to them or customers absent a permanent decoupling mechanism, for potential distribution depending on the results of a final appellate court order. PGL, NSG, and the Illinois Attorney General each requested clarification from the ICC regarding this language, but the ICC has not yet ruled and has no deadline or obligation to do so. Under current Illinois precedent, a utility generally cannot be required to reverse amounts previously recovered or refunded prior to an appellate court decision overturning an ICC-approved rate. Generally, any reversal only applies to periods after an appellate court decision. Under the permanent decoupling mechanism, amounts deferred are subject to an annual reconciliation, with recoveries or refunds occurring in April through December of the following calendar year. We expect to recover or refund amounts deferred in 2012 beginning in April 2013. As of March 31, 2012, PGL recorded approximately $12 million and NSG recorded approximately $1 million under the permanent decoupling mechanism as regulatory assets pending future recovery. However, these amounts will change throughout the remainder of 2012 based on actual customer usage. At this time, management believes recovery is probable; however, depending on the nature and timing of any appellate court decision, the ability to ultimately recover or refund amounts under decoupling could be affected. In addition, an appeal of the pilot decoupling order, which was effective March 2008 through February 2012, is pending and, depending on the outcome, could impact the permanent decoupling mechanism.

Rider ICR

On January 21, 2010, the ICC approved a rider mechanism for PGL to earn a return on and recover the costs, above an annual baseline, of the AMRP through a special charge on customers’ bills, known as Rider ICR. The AMRP is a 20-year project that began in 2011 under which PGL is replacing its cast iron and ductile iron pipes with steel and polyethylene pipes. In June 2010, the ICC issued a rehearing order approving PGL’s proposed baseline of $45.28 million with an annual escalation factor. Recovery of costs for the AMRP became effective on April 1, 2011. On September 30, 2011, the Illinois Appellate Court, First District, reversed the ICC’s approval of Rider ICR, concluding it was improper single issue ratemaking. PGL and the ICC filed for leave to appeal with the Illinois Supreme Court, but their requests were denied. In March 2012, the Illinois Appellate Court remanded the matter to the ICC for further proceeding consistent with its September 30, 2011 decision. As a result, it is possible that the ICC may require PGL to refund amounts previously collected from customers under Rider ICR related to deliveries on or after September 30, 2011.

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2009 Illinois Legislation

In July 2009, Illinois Senate Bill (SB) 1918 was signed into law. Under SB 1918, PGL and NSG filed a bad debt rider with the ICC in September 2009 to recover or refund the incremental difference between the rate case authorized uncollectible expense and the actual uncollectible expense reported to the ICC each year. The ICC approved the rider in February 2010. SB 1918 also requires a percentage of income payment plan for low-income utility customers, which became a permanent program in the fourth quarter of 2011. Additionally, SB 1918 requires an energy efficiency program to meet specified energy efficiency standards, which the ICC approved in May 2011. The first program year began in  June 2011. Finally, SB 1918 requires an on-bill financing program that PGL and NSG will operate with their energy efficiency program. The program began in October 2011 and allows certain residential customers to borrow funds from a third-party lender to invest in energy saving measures and to pay the funds back over time through a charge on their utility bill.

Minnesota

2011 Rates

On November 30, 2010, MERC filed an application with the MPUC to increase retail natural gas rates by $15.2 million. The filing includes a request for an 11.25% return on common equity and a common equity ratio of 50.20% in MERC’s regulatory capital structure. On January 28, 2011, the MPUC approved an interim rate order authorizing MERC a retail natural gas rate increase of $7.5 million, effective February 1, 2011. The interim rates reflect a 10.21% return on common equity and a common equity ratio of 50.20% in MERC’s regulatory capital structure. On April 2, 2012, the Administrative Law Judge filed a proposed order to increase retail natural gas rates by $10.7 million. The proposed order includes a 9.41% return on common equity and a common equity ratio of 50.48% in MERC’s regulatory capital structure. The interim rate increase is subject to refund pending the final rate order, which is expected in the second half of 2012.

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 for the 16-month transitional period. The remaining amount was considered probable of recovery due to inconsistencies between the FERC’s SECA order and the transmission owners’ compliance filings. Integrys Energy Services protested FERC’s 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 September 30, 2011, the FERC denied rehearing of its order on the Initial Decision. The FERC has not yet issued an order on the compliance filings made by transmission owners.

As of March 31, 2012, Integrys Energy Services expected to receive future refunds of $3.8 million. Once the orders on compliance filings are issued, refunds will be made. Any refunds will include interest for the period from payment to refund.

NOTE 20—SEGMENTS OF BUSINESS

At March 31, 2012, we reported five segments, which are described below.

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

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

· The electric transmission investment segment includes our approximate 34% ownership interest in ATC. ATC is a federally regulated electric transmission company with operations in Wisconsin, Michigan, Minnesota, and Illinois.

· Integrys Energy Services is a diversified nonregulated retail energy supply and services company that primarily sells electricity and natural gas to commercial, industrial, and residential customers 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 and the PELLC holding company, along with any nonutility activities at WPS, UPPCO, PGL, NSG, MERC, MGU, and IBS. The operations of ITF were included in this segment beginning on September 1, 2011, when we acquired Trillium USA and Pinnacle CNG Systems.

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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, 2012
External revenues	$	664.0		$	307.0		$	—	$	971.0		$	272.8		$	7.5		$	—		$	1,251.3
Intersegment revenues	1.7			—			—		1.7			0.2			0.7			(2.6		)	—
Depreciation and amortization expense	32.4			22.0			—		54.4			2.9			5.5			(0.1		)	62.7
Earnings in 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			0.6			12.9			(4.2		)	30.5
Provision (benefit) for income taxes	51.5			10.2			7.5		69.2			(12.9		)	(9.5		)	—			46.8
Net income (loss) from continuing operations	78.7			25.0			13.3		117.0			(20.1		)	0.9			—			97.8
Discontinued operations	—			—			—		—			—			1.9			—			1.9
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

	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, 2011
External revenues	$	851.3		$	317.4		$	—	$	1,168.7		$	455.2	$	3.2		$	—		$	1,627.1
Intersegment revenues	2.1			5.2			—		7.3			0.3		0.4			(8.0		)	—
Depreciation and amortization expense	31.2			22.1			—		53.3			3.3		5.8			(0.1		)	62.3
Earnings in equity method investments	—			—			19.2		19.2			—		0.2			—			19.4
Miscellaneous income	0.1			0.3			—		0.4			0.9		6.0			(5.5		)	1.8
Interest expense	12.4			12.0			—		24.4			0.5		15.4			(5.5		)	34.8
Provision (benefit) for income taxes	52.2			11.8			7.8		71.8			5.6		(5.7		)	—			71.7
Net income (loss) from continuing operations	77.4			25.7			11.4		114.5			10.7		(1.8		)	—			123.4
Discontinued operations	—			—			—		—			0.1		—			—			0.1
Preferred stock dividends of subsidiary	(0.2		)	(0.6		)	—		(0.8		)	—		—			—			(0.8		)
Net income (loss) attributed to common shareholders	77.2			25.1			11.4		113.7			10.8		(1.8		)	—			122.7

NOTE 21—NEW ACCOUNTING PRONOUNCEMENTS

Recently Adopted Accounting Guidance

We adopted ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS).”  The amendments change the wording used to describe the requirements for measuring fair value and also require new disclosures about fair value measurements. The amendments also clarify the intent concerning the application of existing fair value measurement requirements. Adoption of this new guidance resulted in new disclosures in Note 17, “Fair Value,” but did not affect our fair value measurements.

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We adopted ASU 2011-05, “Presentation of Comprehensive Income,” and ASU 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05.” The guidance requires that the total of comprehensive income, the components of net income, and the components of OCI be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. We elected to include a separate statement of comprehensive income.

ASU 2011-08, “Testing Goodwill for Impairment,” was effective January 1, 2012. The amendments give companies an option to first perform a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If a company concludes that this is the case, the 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 in the first quarter of 2012.

Recently Issued Accounting Guidance Not Yet Effective

ASU 2011-11, “Disclosures about Offsetting Assets and Liabilities,” was issued in December 2011. The guidance requires enhanced disclosures about offsetting and related arrangements. This guidance is effective for our reporting period ending March 31, 2013. Management is currently evaluating the impact that the adoption of this standard will have on our financial statements.

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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, 2011.

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 operating in Wisconsin, Michigan, Minnesota, and Illinois), and nonregulated energy operations.

RESULTS OF OPERATIONS

Earnings Summary

	Three Months Ended						Change in
	March 31						2012 Over
(Millions, except per share amounts)	2012			2011			2011
Natural gas utility operations	$	78.6		$	77.2		1.8	%
Electric utility operations	24.3			25.1			(3.2	)%
Electric transmission investment	13.3			11.4			16.7	%
Integrys Energy Services’ operations	(20.1		)	10.8			N/A
Holding company and other operations	2.8			(1.8		)	N/A
Net income attributed to common shareholders	$	98.9		$	122.7		(19.4	)%
Basic earnings per share	$	1.26		$	1.57		(19.7	)%
Diluted earnings per share	$	1.25		$	1.56		(19.9	)%
Average shares of common stock
Basic	78.6			78.3			0.4	%
Diluted	79.2			78.6			0.8	%

First Quarter 2012 Compared with First Quarter 2011

Our 2012 first quarter earnings were $98.9 million, compared with 2011 first quarter earnings of $122.7 million. The $23.8 million decrease in earnings was driven by:

·A $25.5 million after-tax non-cash decrease in Integrys Energy Services’ margins related to derivative and inventory fair value adjustments.

·A $5.5 million after-tax decrease in Integrys Energy Services’ realized margins.

·A $3.2 million after-tax decrease in electric utility margins, driven by a decrease in wholesale margins due to lower sales volumes, as well as the write-off of UPPCO’s net regulatory asset related to decoupling.

These decreases were partially offset by:

·A $5.9 million increase from the remeasurement of unrecognized tax benefit liabilities.

·      A $2.6 million after-tax decrease in interest expense, driven by lower average outstanding long-term debt in 2012.

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Regulated Natural Gas Utility Segment Operations

							Change in
	Three Months Ended March 31						2012 Over
(Millions, except heating degree days)	2012			2011			2011
Revenues	$	665.7		$	853.4		(22.0	)%
Purchased natural gas costs	346.5			531.1			(34.8	)%
Margins	319.2			322.3			(1.0	)%
Operating and maintenance expense	135.3			139.8			(3.2	)%
Depreciation and amortization expense	32.4			31.2			3.8	%
Taxes other than income taxes	9.5			9.4			1.1	%
Operating income	142.0			141.9			0.1	%
Miscellaneous income	0.2			0.1			100.0	%
Interest expense	(12.0		)	(12.4		)	(3.2	)%
Other expense	(11.8		)	(12.3		)	(4.1	)%
Income before taxes	$	130.2		$	129.6		0.5	%
Retail throughput in therms
Residential	606.4			782.4			(22.5	)%
Commercial and industrial	183.4			238.4			(23.1	)%
Other	18.7			21.5			(13.0	)%
Total retail throughput in therms	808.5			1,042.3			(22.4	)%
Transport throughput in therms
Residential	87.1			114.5			(23.9	)%
Commercial and industrial	476.7			536.7			(11.2	)%
Total transport throughput in therms	563.8			651.2			(13.4	)%
Total throughput in therms	1,372.3			1,693.5			(19.0	)%
Weather
Average heating degree days	2,589			3,562			(27.3	)%

First Quarter 2012 Compared with First Quarter 2011

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 revenues since we pass through prudently incurred natural gas commodity costs to our customers in current rates. There was an approximate 16% decrease in the average per-unit cost of natural gas sold during the first quarter of 2012, which had no impact on margins.

Regulated natural gas utility segment margins decreased $3.1 million, driven by:

·      An approximate $9 million net decrease in margins as a result of a 19.0% decrease in volumes sold.

·Warmer weather during the first quarter of 2012, as shown by the 27.3% decrease in heating degree days, drove an approximate $53 million decrease in margins.

·Higher sales volumes excluding the impact of weather resulted in an approximate $10 million increase in margins. This increase was due to a combination of both higher use per customer and higher average customer counts, which we primarily attribute to improved economic conditions for certain customers.

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·The net margin decrease due to sales volumes was partially offset by an approximate $34 million quarter-over-quarter increase in decoupling recovery at certain natural gas utilities. Although decoupling was implemented to minimize the impact of changes in sales volumes, it does not cover all jurisdictions or customers. During 2012, decoupling lessened the negative impact from some of the decreased sales volumes through higher future recoveries from customers. During 2011, decoupling lessened the positive impact from some of the increased sales volumes through higher future refunds to customers.

·An approximate $3 million decrease in margins related to certain riders at PGL and NSG. Higher regulatory refunds and lower regulatory recoveries under these riders are offset by equal decreases in operating and maintenance expense, resulting in no impact on earnings.

·We recovered approximately $4 million less for environmental cleanup costs at our former manufactured gas plant sites in 2012. The lower recovery reflects a pass-through to our customers in rates of an environmental settlement received from a potentially responsible party’s performance and payment bond. See Note 11, “Commitment and Contingencies,” for more information about the manufactured gas plant sites.

·We refunded approximately $1 million more to customers under bad debt riders in 2012. See Note 19, “Regulatory Environment,” for more information.

·We billed approximately $2 million more to customers for energy efficiency programs in 2012. See Note 19, “Regulatory Environment,” for more information.

The decrease in margins was partially offset by:

·An approximate $10 million net increase in margins from rate orders. See Note 19, “Regulatory Environment,” for more information on these rate orders.

·The rate increase at PGL, effective January 21, 2012, and other impacts of rate design, had an approximate $14 million positive impact on margins.

·A reduction in rates at WPS, effective January 1, 2012, resulted in an approximate $3 million negative impact on margins. The rate decrease was driven by reduced contributions to the Focus on Energy Program, which promotes residential and small business energy efficiency and renewable energy products. The margin impact from the reduction in contributions is offset by lower operating expenses, resulting in no impact on earnings.

Operating Income

Operating income at the regulated natural gas utility segment increased $0.1 million. This increase was primarily driven by a $4.5 million decrease in operating and maintenance expenses, partially offset by the $3.1 million decrease in margins discussed above and a $1.2 million increase in depreciation and amortization expense.

The decrease in operating and maintenance expenses primarily related to:

·A $3.5 million decrease in employee benefit expenses, primarily driven by lower postretirement and employee health care costs. Lower postretirement expenses were driven by an increase in plan assets due to contributions to our trust. Lower employee health claims experience contributed to the decrease in employee health care costs.

·An approximate $3 million net decrease due to higher amortization of regulatory liabilities related to bad debt riders, lower amortization of regulatory assets related to environmental cleanup costs for manufactured gas plant sites, and an increase in expense and regulatory liabilities related to energy efficiency programs, all at PGL and NSG. Margins decreased by an equal amount, resulting in no impact on earnings.

·A $2.9 million decrease in energy efficiency program expenses related to WPS’s Focus on Energy Program and MERC’s conservation improvement program. Costs for both programs are recovered in rates, resulting in no impact on earnings.

·A $1.8 million decrease in injuries and damages expense resulting from a large number of claims accrued in the first quarter of 2011.

·A $1.7 million decrease in bad debt expense, driven by a new cost of gas component included as part of PGL’s and NSG’s bad debt expense tracking mechanisms. The change in the bad debt mechanisms was approved in PGL’s and NSG’s most recent rate orders, effective January 21, 2012. As a result of this component, bad debt expense was partially impacted by lower natural gas costs in 2012 and the decrease in volumes related to warmer weather discussed above.

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·These decreases were partially offset by a $7.4 million increase in natural gas distribution costs. Costs associated with permits, restoration, transportation, and other miscellaneous distribution costs contributed to the increase.

Regulated Electric Utility Segment Operations

							Change in
	Three Months Ended March 31						2012 Over
(Millions, except degree days)	2012			2011			2011
Revenues	$	307.0		$	322.6		(4.8	)%
Fuel and purchased power costs	127.5			137.8			(7.5	)%
Margins	179.5			184.8			(2.9	)%
Operating and maintenance expense	100.3			101.2			(0.9	)%
Depreciation and amortization expense	22.0			22.1			(0.5	)%
Taxes other than income taxes	12.9			12.3			4.9	%
Operating income	44.3			49.2			(10.0	)%
Miscellaneous income	0.1			0.3			(66.7	)%
Interest expense	(9.2		)	(12.0		)	(23.3	)%
Other expense	(9.1		)	(11.7		)	(22.2	)%
Income before taxes	$	35.2		$	37.5		(6.1	)%
Sales in kilowatt-hours
Residential	775.2			814.3			(4.8	)%
Commercial and industrial	2,087.8			2,053.2			1.7	%
Wholesale	1,023.5			1,062.2			(3.6	)%
Other	10.9			11.0			(0.9	)%
Total sales in kilowatt-hours	3,897.4			3,940.7			(1.1	)%
Weather
WPS:
Heating degree days	2,864			3,892			(26.4	)%
Cooling degree days	11			—			N/A
UPPCO:
Heating degree days	3,282			4,108			(20.1	)%

First Quarter 2012 Compared with First Quarter 2011

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 decreased $5.3 million, driven by:

·An approximate $3 million decrease in margins due to impacts from the WPS 2012 rate case re-opener. The PSCW approved a rate increase effective January 1, 2012. The rate increase was driven by anticipated increases in fuel and purchased power costs that did not materialize. Under the fuel rules, WPS deferred a portion of the difference between the costs included in rates and the actual fuel costs. This portion will be refunded to customers. Excluding the impact from fuel and purchased power costs, the 2012 rate case re-opener resulted in a rate decrease. The rate decrease was driven by reduced contributions to the Focus on Energy Program, which promotes residential and small business energy efficiency and renewable energy products. The margin impact from the reduction in contributions to the Focus on Energy Program was offset by lower operating expenses due to reduced payments to the program in 2012.

·An approximate $2 million decrease in wholesale margins, driven by a decrease in sales volumes. The decrease was primarily due to the loss of wholesale customers and a reduction in sales to one large customer.

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·A $1.5 million decrease in margins due to the write-off of UPPCO’s net regulatory asset related to its 2010 and 2011 decoupling deferrals. The write-off was the result of the Michigan Court of Appeals ruling in a Detroit Edison case which held that the MPSC did not have the authority to approve electric decoupling mechanisms.

·These decreases were partially offset by:

·An approximate $1 million increase in margins due to a retail electric rate increase at UPPCO, effective January 1, 2012.

·An approximate $1 million increase in margins from large commercial and industrial customers due to a 4.1% increase in sales volumes. We primarily attribute this increase to improved economic conditions.

Operating Income

Operating income at the regulated electric utility segment decreased $4.9 million. The decrease was driven by the $5.3 million decrease in margins, partially offset by a $0.4 million decrease in operating expenses. The decrease in operating expenses was driven by:

·A $2.8 million decrease in customer assistance expense related to payments made to the Focus on Energy Program. These payments are recovered in rates, resulting in no impact on earnings.

·This decrease was partially offset by:

·A $1.5 million increase in employee benefit expenses.

·A $0.6 million increase in taxes other than income taxes, driven by increases in property taxes and payroll taxes.

Other Expense

Other expense decreased $2.6 million, driven by a decrease in interest expense due to the maturity and repayment of $150 million of long-term debt at WPS in August 2011.

Electric Transmission Investment Segment Operations

First Quarter 2012 Compared with First Quarter 2011

Miscellaneous Income

Miscellaneous income at the electric transmission investment segment increased $1.6 million. The increase resulted from higher earnings related to our approximate 34% ownership interest in ATC. We earn higher returns each year as ATC continues to increase its rate base by investing in transmission equipment and facilities for improved reliability and economic benefits for customers.

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Integrys Energy Services Nonregulated Segment Operations

	Three Months Ended March 31						Change in 2012 over
(Millions, except natural gas sales volumes)	2012			2011			2011
Revenues	$	273.0		$	455.5		(40.1	)%
Cost of sales	271.7			402.5			(32.5	)%
Margins	1.3			53.0			(97.5	)%
Margin Detail
Realized retail electric margins	16.9			20.3			(16.7	)%
Realized wholesale electric margins (1)	(0.5		)	(0.3		)	66.7	%
Realized energy asset margins	5.1			7.3			(30.1	)%
Fair value accounting adjustments	(43.5		)	10.0			N/A
Electric and other margins	(22.0		)	37.3			N/A
Realized retail natural gas margins	23.5			23.5			—
Realized wholesale natural gas margins (1)	(0.6		)	2.8			N/A
Lower-of-cost-or-market inventory adjustments	1.6			0.1			1,500.0	%
Fair value accounting adjustments	(1.2		)	(10.7		)	(88.8	)%
Natural gas margins	23.3			15.7			48.4	%
Operating and maintenance expense	29.2			32.0			(8.8	)%
Depreciation and amortization	2.9			3.3			(12.1	)%
Taxes other than income taxes	2.3			1.8			27.8	%
Operating (loss) income	(33.1		)	15.9			N/A
Miscellaneous income	0.7			0.9			(22.2	)%
Interest expense	(0.6		)	(0.5		)	20.0	%
Other income	0.1			0.4			(75.0	)%
(Loss) income before taxes	$	(33.0	)	$	16.3		N/A
Physically settled volumes
Retail electric sales volumes in kwh	2,918.9			2,952.5			(1.1	)%
Wholesale assets and distributed solar electric sales volumes in kwh (2)	88.9			72.6			22.5	%
Retail natural gas sales volumes in bcf	43.8			48.5			(9.7	)%

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 2012 Compared with First Quarter 2011

Revenues

Revenues decreased $182.5 million, driven by lower quarter-over-quarter average commodity prices.

Margins

Integrys Energy Services’ margins decreased $51.7 million. The significant items contributing to the change in margins were as follows:

Electric and Other Margins

Realized retail electric margins

Realized retail electric margins decreased $3.4 million. The decrease was driven by the expiration at the end of 2011 of several large, lower-margin customer contracts in the Illinois market.

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Realized energy asset margins

Realized energy asset margins decreased $2.2 million. The decrease was primarily due to the expiration of a long-term capacity contract in the fourth quarter of 2011.

Fair value accounting adjustments

Derivative accounting rules impact Integrys Energy Services’ margins. Fair value adjustments caused a $53.5 million decrease in electric margins quarter over quarter. These adjustments primarily relate to physical and financial contracts used to reduce price risk for supply associated with electric sales contracts. These adjustments will reverse in future periods as contracts settle.

Natural Gas Margins

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 $1.5 million quarter-over-quarter increase in margins from inventory adjustments was driven by a higher volume of inventory withdrawn from storage for which write-downs had previously been recorded.

Fair value accounting adjustments

Derivative accounting rules impact Integrys Energy Services’ margins. Fair value adjustments caused a $9.5 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 (Loss) Income

Integrys Energy Services’ operating income decreased $49.0 million. The main driver of the decrease was the $51.7 million decrease in margins discussed above, partially offset by a $2.8 million decrease in operating and maintenance expenses driven by a $2.9 million decrease in employee benefit expenses.

Holding Company and Other Segment Operations

							Change in
	Three Months Ended March 31						2012 over
(Millions)	2012			2011			2011
Operating income (loss)	$	(1.6	)	$	1.7		N/A
Other expense	(7.0		)	(9.2		)	(23.9	)%
Net loss before taxes	$	(8.6	)	$	(7.5	)	14.7	%

First Quarter 2012 Compared with First Quarter 2011

Operating Income (Loss)

Operating income at the holding company and other segment decreased $3.3 million in 2012. The decrease was driven partially by operating losses of $1.7 million at ITF, a subsidiary formed in September 2011 to hold our compressed natural gas businesses. Lower intercompany fees of $1.4 million charged by the holding company to Integrys Energy Services, related to lower interest charges and decreased use of an intercompany credit agreement, also contributed to the decrease in operating income.

Other Expense

Other expense at the holding company and other segment decreased $2.2 million in 2012. Interest expense on long-term debt decreased, driven by lower average outstanding long-term debt in 2012.

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Provision for Income Taxes

	Three Months Ended March 31
	2012		2011
Effective Tax Rate	32.4	%	36.8	%

First Quarter 2012 Compared with First Quarter 2011

Our effective tax rate decreased in the first quarter of 2012. This decrease primarily related to a remeasurement of our unrecognized tax benefit liability that better reflects how the underlying uncertain tax positions are resolving themselves in various taxing jurisdictions.

Discontinued Operations

First Quarter 2012 Compared with First Quarter 2011

Income from discontinued operations, net of tax, increased $1.8 million in 2012. During the first quarter of 2012, we recorded an after-tax gain in discontinued operations at the holding company and other segment when we remeasured an unrecognized tax benefit liability that better reflects how the underlying uncertain tax positions are resolving themselves in various taxing jurisdictions.

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.

Operating Cash Flows

During the quarter ended March 31, 2012, net cash provided by operating activities was $225.8 million, compared with $395.5 million for the same quarter in 2011. The $169.7 million decrease in net cash provided by operating activities was largely driven by:

·A $140.2 million increase in contributions to pension and other postretirement benefit plans.

·A decrease in net income, adjusted for non-cash items.

·Partially offsetting these decreases was a quarter-over-quarter net increase in cash provided by working capital of $6.3 million. This increase was primarily due to the following:

·A $49.9 million decrease in accounts receivable and accrued unbilled revenues in 2012, compared to a $50.1 million increase in 2011. The change was driven by the warmer quarter-over-quarter weather and the decline in natural gas prices that occurred in the first quarter of 2012.

·A positive impact from an $18.7 million increase in other current liabilities in 2012, compared with a $26.0 million decrease in other current liabilities in 2011. This change was driven by increases in 2012 in PGL’s and NSG’s liabilities related to natural gas costs refundable through rate adjustments versus decreases in these liabilities in 2011.

·A $26.2 million positive impact from a quarter-over-quarter decrease in other current assets. The change was driven by higher tax refunds accrued in 2011, compared with 2012, primarily due to 100% bonus depreciation and increased tax deductions for pension funding in 2011. In addition, we received federal and state income tax refunds in the first quarter of 2012.

·These increases in cash provided by working capital were partially offset by a $53.6 million quarter-over-quarter increase in cash used for accounts payable, a $20.0 million quarter-over-quarter decrease in cash generated from inventory, and an $82.5 million quarter-over-quarter decrease in the temporary LIFO liquidation credit, all of which were driven by the warmer weather and the decline in natural gas prices that occurred in the first quarter of 2012.

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Investing Cash Flows

Net cash used for investing activities was $136.7 million during the quarter ended March 31, 2012, compared with $56.2 million for the same quarter in 2011. The $80.5 million increase in net cash used for investing activities was primarily due to a $71.8 million increase in cash used to fund capital expenditures (discussed below).

Capital Expenditures

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

Reportable Segment (millions)	2012		2011		Change
Electric utility	$	30.8	$	20.7	$	10.1
Natural gas utility	78.9		26.6		52.3
Integrys Energy Services	8.2		1.2		7.0
Holding company and other	5.1		2.7		2.4
Integrys Energy Group consolidated	$	123.0	$	51.2	$	71.8

The increase in capital expenditures at the natural gas utility segment for the quarter ended March 31, 2012, compared with March 31, 2011, was primarily a result of the AMRP at PGL. The increase in capital expenditures at the electric utility segment was driven by various projects at the Columbia plant in 2012, partially offset by the purchase of a previous joint owner’s interest in a combustion turbine in 2011.

Financing Cash Flows

Net cash used for financing activities was $74.9 million during the quarter ended March 31, 2012, compared with $323.0 million for the same quarter in 2011. The $248.1 million decrease in net cash used for financing activities was driven by:

·The repayment of $325.0 million of long-term debt in 2011.

·Partially offsetting this decrease in net cash used was a $55.7 million decrease in cash received from net short-term borrowings.

Significant Financing Activities

For information on short-term debt, see Note 8, “Short-Term Debt and Lines of Credit.”

For information on the issuance and redemption of long-term debt in 2012, see Note 9, “Long-Term Debt.”

From February 11, 2010 through April 30, 2011, we issued new shares of common stock to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans. Beginning May 1, 2011, shares were purchased on the open market to meet the requirements of these plans.

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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 January 24, 2012, Standard & Poor’s raised the issuer credit ratings for us, PGL, and NSG to “A-” from “BBB+.”  In addition, they raised our senior unsecured debt rating to “BBB+” from “BBB” and raised our junior subordinated notes rating to “BBB” from “BBB-.” The outlook for us, PGL, and NSG was revised to “stable” from “positive.” According to Standard & Poor’s, the revised ratings reflect their view that our business risk profile improved to “excellent” from “strong” and that we continue to have a significant financial risk profile. The revised business risk profile assessment reflects the successful implementation of our strategic initiative to reduce our exposure to the nonutility businesses and our effective management of regulatory risk. WPS’s outlook remained “stable.”

Future Capital Requirements and Resources

Contractual Obligations

The following table shows our contractual obligations as of March 31, 2012, including those of our subsidiaries.

			Payments Due By Period
(Millions)	Total Amounts Committed		2012		2013 to 2014		2015 to 2016		2017 and Thereafter
Long-term debt principal and interest payments (1)	$	2,948.1	$	330.8	$	581.0	$	633.9	$	1,402.4
Operating lease obligations	80.5		6.3		14.0		8.3		51.9
Commodity purchase obligations (2)	2,461.2		487.7		726.3		338.9		908.3
Purchase orders (3)	536.1		534.2		1.9		—		—
Capital contributions to equity method investment	5.1		5.1		—		—		—
Pension and other postretirement funding obligations (4)	574.1		42.9		201.2		60.0		270.0
Total contractual cash obligations	$	6,605.1	$	1,407.0	$	1,524.4	$	1,041.1	$	2,632.6

(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 commodity purchase obligations are generally entered into to meet 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.

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(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 2014.

The table above does not reflect payments related to the manufactured gas plant remediation liability of $608.1 million at March 31, 2012, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 11, “Commitments and Contingencies,” for more information about environmental liabilities. The table also does not reflect any payments for the March 31, 2012, liability of $19.7 million related to unrecognized tax benefits, as the amount and timing of the payments are uncertain. See Note 10, “Income Taxes,” for more information on unrecognized tax benefits.

Capital Requirements

As of March 31, 2012, our subsidiaries’ capital expenditures for the three-year period 2012 through 2014 were expected to be as follows:

(Millions)
WPS
Environmental projects	$	511
Electric and natural gas distribution projects	201
Electric and natural gas delivery and customer service projects	64
Other projects	176
UPPCO
Repairs and safety measures at hydroelectric facilities	16
Other projects	32
MGU
Natural gas pipe distribution system, underground natural gas storage facilities, and other projects	35
MERC
Natural gas pipe distribution system and other projects	53
PGL
Natural gas pipe distribution system, underground natural gas storage facilities, and other projects	876
NSG
Natural gas pipe distribution system and other projects	85
Integrys Energy Services
Solar and other projects	99
IBS
Corporate or shared services software and infrastructure projects	96
ITF
Compressed natural gas fueling stations	71
Total capital expenditures	$	2,315

We expect to provide capital contributions to INDU Solar Holdings, LLC, (not included in the above table) of approximately $45 million in 2012.

We expect to provide capital contributions to ATC (not included in the above table) of approximately $19 million from 2012 through 2014.

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, industry restructuring, environmental requirements, regulatory constraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, and economic trends.

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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 2012 through 2014 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. We believe we have adequate financial flexibility and resources to meet our future needs.

At March 31, 2012, 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 8, “Short-Term Debt and Lines of Credit,” for more information on credit facilities and other short-term credit agreements. See Note 9, “Long-Term Debt,” for more information on long-term debt.

Other Future Considerations

Decoupling

In certain jurisdictions, decoupling mechanisms have been implemented. These mechanisms differ state by state and allow utilities to adjust future rates to recover or refund all or a portion of the differences between actual and authorized margin.

·Decoupling for residential and small commercial and industrial sales was approved by the ICC on a four-year trial basis for PGL and NSG, effective March 1, 2008. In the PGL and NSG rate order approved on January 10, 2012, the ICC made the decoupling mechanism (based on total margin, excluding fixed charges) permanent for both companies. Interveners, including the Illinois Attorney General, oppose decoupling and have appealed the ICC’s approval of both the pilot program and the permanent decoupling mechanism. PGL and NSG actively support the ICC’s decision to approve decoupling. The Illinois Attorney General filed a motion with the ICC to stay the implementation of the permanent decoupling mechanism or, in the alternative, make collections subject to refund. The ICC denied the motion. However, the ICC issued an amendatory order with unclear language directing PGL and NSG to identify funds, which would be due to them or customers absent a permanent decoupling mechanism, for potential distribution depending on the results of a final appellate court order. PGL, NSG, and the Illinois Attorney General each requested clarification from the ICC regarding this language, but the ICC has not yet ruled and has no deadline or obligation to do so. Under current Illinois precedent, a utility generally cannot be required to reverse amounts previously recovered or refunded prior to an appellate court decision overturning an ICC-approved rate. Generally, any reversal only applies to periods after an appellate court decision. Under the permanent decoupling mechanism, amounts deferred are subject to an annual reconciliation, with recoveries or refunds occurring in April through December of the following calendar year. We expect to recover or refund amounts deferred in 2012 beginning in April 2013. As of March 31, 2012, PGL recorded approximately $12 million and NSG recorded approximately $1 million under the permanent decoupling mechanism as regulatory assets pending future recovery. However, these amounts will change throughout the remainder of 2012 based on actual customer usage. At this time, management believes recovery is probable; however, depending on the nature and timing of any appellate court decision, the ability to ultimately recover or refund amounts under decoupling could be affected. In addition, an appeal of the pilot decoupling order is pending and, depending on the outcome, could impact the permanent decoupling mechanism.

·Decoupling for natural gas and electric residential and small commercial and industrial sales was approved by the PSCW on a four-year trial basis for WPS, effective January 1, 2009, and ending on December 31, 2012. The mechanism does not adjust for variations in volumes resulting from changes in customer count compared to rate case levels, nor does it cover all customer classes. This decoupling mechanism includes 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 order. Decoupling for 2012 and beyond is currently being addressed in WPS’s 2013 rate case filing.

·Decoupling for UPPCO was approved for the majority of customer classes by the MPSC, effective January 1, 2010, and ended on December 31, 2011. However, 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. As a result of this ruling, we expensed $1.5 million in the first quarter of 2012 related to electric decoupling amounts previously deferred for regulatory recovery at UPPCO. It is unknown at this time whether the ruling will be appealed. The MPSC opened a docket seeking comments regarding (1) the impact of the Court of Appeals decision on each of the affected utilities and their customers, and (2) opinions concerning the future, if any, of the use of electric decoupling mechanisms in Michigan.

·The MPSC granted an order, effective January 1, 2010, approving a decoupling mechanism for MGU that covers residential and small commercial and industrial customers. The decoupling mechanism does not adjust for weather-related usage, nor does it adjust for variations in volumes resulting from changes in customer count compared to rate case levels. The decoupling mechanism does not cover all customer classes. The Court of Appeals ruling discussed above did not affect MGU’s decoupling mechanism because it did not apply to natural gas.

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·In Minnesota, MERC proposed a decoupling mechanism in its November 30, 2010 general rate case filing, which was recommended in the Administrative Law Judge’s proposed order on April 2, 2012. A final order is expected in the second half of 2012.

See Note 19, “Regulatory Environment,” for more information.

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 December 2010, the EPA announced its intent to develop new source performance standards for greenhouse gas emissions. The standards would apply to new and modified, as well as existing, electric utility steam generating units. On March 27, 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 planned to propose performance standards for existing units in 2011 and finalize them in 2012; however, that proposal has been delayed.

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

Federal Health Care Reform

In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (HCR) were signed into law. HCR contains various provisions that will affect the cost of providing health care coverage to our active and retired employees and their dependents. Although these provisions become effective at various times over the next 10 years, some provisions that affect the cost of providing benefits to retirees were reflected in our financial statements in 2010 and 2011.

Beginning in 2013, a provision of HCR will eliminate the tax deduction for employer-paid postretirement prescription drug charges to the extent those charges will be offset by the receipt of a federal Medicare Part D subsidy. As a result, we eliminated $11.8 million of our deferred tax asset related to postretirement benefits in 2010. Of this amount, $10.8 million flowed through to net income as a component of income tax expense in 2010. The remaining $1.0 million was deferred for regulatory recovery at UPPCO. An additional $1.5 million was expensed in June 2011 for deferred income taxes related to a Wisconsin tax law change. In the fourth quarter of 2011, PGL and NSG recorded a regulatory asset of $5.8 million, reversing amounts previously expensed in 2010, as PGL and NSG were authorized recovery of these amounts in the rate order approved on January 10, 2012. In addition, WPS was authorized recovery in February 2012 for the portion related to its Michigan operations that was previously expensed in 2010. We have sought rate recovery for the remaining $5.9 million of income tax expense that relates to this tax law change associated with our regulated operations. If recovery in rates becomes probable in Wisconsin, income tax expense will be reduced in that period. We are not currently able to predict how much of the remaining portion, if any, will be recovered in rates.

Other provisions of HCR include the elimination of certain annual and lifetime maximum benefits and the broadening of plan eligibility requirements. It also includes the elimination of pre-existing condition restrictions, an excise tax on high-cost health plans, changes to the Medicare Part D prescription drug program, and numerous other changes. We successfully participated in the Early Retiree Reinsurance Program through the third quarter of 2011. Following the submission of our fourth quarter 2011 claim, we were informed that the program fund had been depleted and, as such, we are not anticipating any future funding.

Major provisions of HCR are currently being challenged and are under review by the United States Supreme Court. The Supreme Court is expected to rule on this matter in the second quarter of 2012. Until then, key provisions of HCR remain uncertain. We continue to assess the extent to which the provisions of the new law will affect our future health care and related employee benefit plan costs.

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

The Dodd-Frank Act was signed into law in July 2010. However, significant rulings essential to its framework still remain outstanding. Depending on the final rules, certain provisions of the Dodd-Frank Act relating to derivatives could increase capital and/or collateral requirements. Since final rules for some of the most key elements relating to derivatives continue to be delayed, it is difficult to predict when the rules will be finalized at this time. We are monitoring developments related to this act and their potential impacts on our future financial results.

Federal Tax Law Changes

In December 2010, President Obama signed into law The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. This act includes tax incentives, such as an extension and increase of bonus depreciation, the extension of the research and experimentation credit, and the extension of treasury grants in lieu of claiming the investment tax credit or production tax credit for certain renewable energy investments. In September 2010, President Obama signed into law the Small Business Jobs Act of 2010. This act includes tax incentives that affect us, such as an extension to bonus depreciation and changes to listed property. We anticipate that these tax law changes will likely result in $140.0 million to $240.0 million of reduced cash payments for taxes during 2012. These tax incentives may also reduce utility rate base and, thus, future earnings relative to prior expectations. We have primarily used the proceeds from these incentives to make incremental contributions to our various employee benefit plans. In addition, these tax incentives have helped reduce our financing needs.

In December 2011, the National Defense Authorization Act (NDAA) was enacted. The most significant provision of the NDAA was to retroactively eliminate the application of the tax normalization rule for cash grants taken by a regulated utility in lieu of the investment tax credit or production tax credits. Prior to the enactment of NDAA, a regulated utility would have been required to amortize the grant in rates over the regulatory life of the renewable energy generating plant. Further, the allowed rate of return on the generating plant could not be reduced by the unamortized grant balance during the life of the plant. As a result of the enactment of NDAA, we are evaluating our options for taking advantage of cash grants in lieu of the production tax credits we are currently claiming for WPS’s Crane Creek wind project.

CRITICAL ACCOUNTING POLICIES

We have reviewed our critical accounting policies for new critical accounting estimates and other significant changes and have found that the disclosures made in our Annual Report on Form 10-K for the year ended December 31, 2011, are still current and that there have been no significant changes.

46

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 may 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 non-discounted 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 2011 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)	2012		2011
As of March 31	$	0.1	$	0.3
Average for 12 months ended March 31	0.1		0.3
High for 12 months ended March 31	0.2		0.3
Low for 12 months ended March 31	0.1		0.2

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

(Millions)	2012		2011
As of March 31	$	0.4	$	1.2
Average for 12 months ended March 31	0.5		1.4
High for 12 months ended March 31	0.7		1.5
Low for 12 months ended March 31	0.4		1.1

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 variable rate long-term debt and short-term borrowings. 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, 2012, a hypothetical increase in market interest rates of 100 basis points would have increased annual interest expense by $3.3 million. Comparatively, based on the variable rate debt outstanding at March 31, 2011, an increase in interest rates of 100 basis points would have increased annual interest expense by $1.5 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 2011 Annual Report on Form 10-K.

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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, 2012, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II.      OTHER INFORMATION

Item 1.            Legal Proceedings

For information on material legal proceedings and matters, see Note 11, “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 2011 Annual Report on Form 10-K, which was filed with the SEC on February 29, 2012.

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 15, “Common Equity.”

Issuer Purchases of Equity Securities

The following table provides a summary of common stock purchases for the three months ended March 31, 2012:

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
01/01/12 - 01/31/12 (1) (2)	16,848	$	52.97	—	—
02/01/12 - 02/29/12 (1) (2) (3)	246,834	54.10		—	—
03/01/12 - 03/31/12 (1) (2) (3)	256,039	53.22		—	—
Total	519,721	$	53.63	—	—

(1)Represents shares purchased in the open market by American Stock Transfer & Trust Company to satisfy obligations under various equity compensation plans.

(2)Represents shares purchased in the open market by American Stock Transfer & Trust Company to provide shares to participants in the Stock Investment Plan.

(3)Represents shares purchased in the open market by American Stock Transfer & Trust Company and held in a rabbi trust under our Deferred Compensation Plan.

Item 6.            Exhibits

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

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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.
Date: May 2, 2012	/s/ Diane L. Ford
	Diane L. Ford
	Vice President and Corporate Controller
	(Duly Authorized Officer and Chief Accounting Officer)

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INTEGRYS ENERGY GROUP
EXHIBIT INDEX TO FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2012

Exhibit No.	Description
12	Computation of Ratio of Earnings to Fixed Charges
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, 2012, filed on May 2, 2012, 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.

* In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.

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EX-12

Exhibit 12

INTEGRYS ENERGY GROUP, INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Three Months Ended March 31			For the Years Ended December 31
(Millions, except ratio)	2012			2011			2010			2009			2008			2007
EARNINGS
Net income (loss) from continuing operations	$	97.8		$	230.9		$	223.5		$	(70.3	)	$	114.8		$	181.0
Provision for income taxes	46.8			133.9			148.2			83.7			61.1			86.0
Income from continuing operations before income taxes	144.6			364.8			371.7			13.4			175.9			267.0
Less:
Undistributed earnings of less than 50% owned affiliates	(4.1		)	(15.8		)	(14.8		)	(16.2		)	(16.4		)	3.8
Preferred stock dividends of subsidiary (a)	(1.2		)	(5.1		)	(5.3		)	0.7			(4.8		)	(5.2		)
Interest capitalized (b)	—			—			—			(0.2		)	—			—
Adjusted income (loss) from continuing operations before income taxes	139.3			343.9			351.6			(2.3		)	154.7			265.6
Total fixed charges as defined	32.7			138.3			158.8			172.3			170.5			174.6
Total earnings as defined	$	172.0		$	482.2		$	510.4		$	170.0		$	325.2		$	440.2
FIXED CHARGES
Interest expense	$	30.5		$	128.8		$	147.9		$	164.8		$	158.1		$	164.5
Interest capitalized (c)	0.1			0.3			0.6			2.6			2.0			0.3
Interest factor applicable to rentals	0.9			4.1			5.0			5.6			5.6			4.6
Preferred stock dividends of subsidiary (a)	1.2			5.1			5.3			(0.7		)	4.8			5.2
Total fixed charges as defined	$	32.7		$	138.3		$	158.8		$	172.3		$	170.5		$	174.6
RATIO OF EARNINGS TO FIXED CHARGES	5.3			3.5			3.2			(d)			1.9			2.5

(a)	Preferred stock dividends of subsidiary are computed by dividing the preferred stock dividends of subsidiary by 100% minus the income tax rate.
(b)	Includes interest capitalized for the nonregulated segments.
(c)	Includes allowance for funds used during construction.
(d)	For 2009, earnings were inadequate to cover fixed charges by $2.3 million, driven by a pre-tax noncash goodwill impairment loss of $291.1 million.

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 2, 2012	/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, Joseph P. O’Leary, 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 2, 2012	/s/ Joseph P. O’Leary
	Joseph P. O’Leary Senior 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, 2012 (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/ Joseph P. O’Leary

Joseph P. O’Leary

Senior Vice President and Chief Financial Officer

Date: May 2, 2012

XML

COMMON EQUITY (Tables)

3 Months Ended

Mar. 31, 2012

COMMON EQUITY

Reconciliation of shares issued and outstanding

	March 31, 2012				December 31, 2011
	Shares	Average Cost			Shares	Average Cost
Common stock issued	78,287,906				78,287,906
Less:
Deferred compensation rabbi trust	371,363	$	45.71	*	382,971	$	44.54	*
Total common shares outstanding	77,916,543				77,904,935

*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)	2012			2011
Numerator:
Net income from continuing operations	$	97.8		$	123.4
Discontinued operations, net of tax	1.9			0.1
Preferred stock dividends of subsidiary	(0.8		)	(0.8		)
Net income attributed to common shareholders	$	98.9		$	122.7
Denominator:
Average shares of common stock — basic	78.6			78.3
Effect of dilutive securities
Stock-based compensation	0.4			0.3
Deferred compensation	0.2			—
Average shares of common stock — diluted	79.2			78.6
Earnings per common share
Basic	$	1.26		$	1.57
Diluted	1.25			1.56

Components of accumulated other comprehensive loss, net of tax

	Cash Flow Hedges			Defined Benefit Pension Plans			Accumulated Other Comprehensive Income (Loss)
Beginning balance at December 31, 2011	$	(11.5	)	$	(31.0	)	$	(42.5	)
Current period other comprehensive income	1.2			0.3			1.5
Ending balance at March 31, 2012	$	(10.3	)	$	(30.7	)	$	(41.0	)

Capital transactions with subsidiaries

Subsidiary	Dividends To Parent		Return Of Capital To Parent		Equity Contributions From Parent
WPS	$	26.4	$	—	$	40.0
WPS Investments, LLC *	16.7		—		3.4
MERC	—		15.0		—
IBS	—		3.0		—
MGU	—		6.0		—
UPPCO	—		2.5		8.5
Total	$	43.1	$	26.5	$	51.9

XML

LONG-TERM DEBT (Details) (USD $) In Millions, unless otherwise specified													3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2012 Other term loan	Dec. 31, 2011 Other term loan	Mar. 31, 2012 WPS	Dec. 31, 2011 WPS	Mar. 31, 2012 WPS 4.875% Senior Notes due 2012	Mar. 31, 2012 WPS 3.95% Senior Notes due 2013	Mar. 31, 2012 PGL	Dec. 31, 2011 PGL	Mar. 31, 2012 NSG	Dec. 31, 2011 NSG	Mar. 31, 2012 NSG First Mortgage Series M, 5.00% bonds due 2028	Mar. 31, 2012 NSG First Mortgage Series P, 3.43% bonds	Mar. 31, 2012 INTEGRYS ENERGY GROUP, INC.	Dec. 31, 2011 INTEGRYS ENERGY GROUP, INC.	Mar. 31, 2012 INTEGRYS ENERGY GROUP, INC. 5.375% Unsecured Senior Notes due 2012
LONG-TERM DEBT
Total	$ 2,123.6	$ 2,123.6	$ 27.0	$ 27.0	$ 722.1	$ 722.1	$ 150.0	$ 22.0	$ 525.0	$ 525.0	$ 74.7	$ 74.7		$ 28.0	$ 774.8	$ 774.8	$ 100.0
Unamortized discount and premium on bonds and debt	(1.5)	(1.6)
Total debt	2,122.1	2,122.0
Less current portion	(272.0)	(250.0)
Total long-term debt	1,850.1	1,872.0
Interest rate stated percentage							4.875%	3.95%					5.00%	3.43%			5.375%
Amount of notes bought back													$ 28.2
Interest rate as of reporting date (as a percent)			0.20%

XML

DISCONTINUED OPERATIONS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Discontinued operations
Discontinued operations, net of tax	$ 1.9	$ 0.1
Integrys Energy Services
Discontinued operations
Discontinued operations, net of tax		0.1
Holding Company and Other
Discontinued operations
Discontinued operations, net of tax	$ 1.9

XML

FAIR VALUE (Details 2) (Nonregulated Segments, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Electric contracts
Transfers between the levels of the fair value hierarchy
Transfers into Level 2 from Level 3	$ (0.1)	$ (2.4)
Transfers into Level 3 from Level 2	(5.0)	(5.4)
Natural gas contracts
Transfers between the levels of the fair value hierarchy
Transfers into Level 2 from Level 3	1.3	0.4
Transfers into Level 3 from Level 2	$ 2.4	$ (0.1)

XML

INCOME TAXES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
INCOME TAXES
Effective tax rate (as a percent)	32.40%	36.80%
Federal statutory tax rate (as a percent)	35.00%	35.00%
Decreased liability for unrecognized tax benefits	$ 2.7

XML

RISK MANAGEMENT ACTIVITIES (Details 4) In Millions, unless otherwise specified	3 Months Ended															1 Months Ended
	Mar. 31, 2011 USD ($)	Mar. 31, 2012 Nonregulated Segments USD ($)	Mar. 31, 2011 Nonregulated Segments USD ($)	Mar. 31, 2011 Nonregulated Segments Interest expense. USD ($)	Mar. 31, 2012 Nonregulated Segments Natural gas contracts Nonregulated revenue USD ($)	Mar. 31, 2011 Nonregulated Segments Natural gas contracts Nonregulated revenue USD ($)	Mar. 31, 2012 Nonregulated Segments Natural gas contracts Nonregulated revenue (reclassified from accumulated OCI) USD ($)	Mar. 31, 2011 Nonregulated Segments Natural gas contracts Nonregulated revenue (reclassified from accumulated OCI) USD ($)	Mar. 31, 2012 Nonregulated Segments Electric contracts Nonregulated revenue USD ($)	Mar. 31, 2011 Nonregulated Segments Electric contracts Nonregulated revenue USD ($)	Mar. 31, 2012 Nonregulated Segments Electric contracts Nonregulated revenue (reclassified from accumulated OCI) USD ($)	Mar. 31, 2011 Nonregulated Segments Electric contracts Nonregulated revenue (reclassified from accumulated OCI) USD ($)	Mar. 31, 2011 Nonregulated Segments Interest rate swaps Interest expense. USD ($)	Mar. 31, 2012 Nonregulated Segments Cash flow hedges Natural gas contracts USD ($)	Mar. 31, 2012 Nonregulated Segments Cash flow hedges Electric contracts USD ($)	Jan. 31, 2011 Nonregulated Segments Fair value hedges Interest rate swaps USD ($)	Mar. 31, 2012 Nonregulated Segments Purchases Natural gas contracts therm	Dec. 31, 2011 Nonregulated Segments Purchases Natural gas contracts therm	Mar. 31, 2012 Nonregulated Segments Purchases Electric contracts kWh	Dec. 31, 2011 Nonregulated Segments Purchases Electric contracts kWh	Mar. 31, 2012 Nonregulated Segments Purchases Foreign exchange contracts CAD	Dec. 31, 2011 Nonregulated Segments Purchases Foreign exchange contracts CAD	Mar. 31, 2012 Nonregulated Segments Sales Natural gas contracts therm	Dec. 31, 2011 Nonregulated Segments Sales Natural gas contracts therm	Mar. 31, 2012 Nonregulated Segments Sales Electric contracts kWh	Dec. 31, 2011 Nonregulated Segments Sales Electric contracts kWh	Mar. 31, 2012 Nonregulated Segments Sales Foreign exchange contracts CAD	Dec. 31, 2011 Nonregulated Segments Sales Foreign exchange contracts CAD
Risk management activities
Pre-tax losses on cash flow hedge expected to be recognized in earnings in the next 12 months														$ (0.9)	$ (4.5)
Gains (losses) recorded related to non-hedge derivatives									(68.6)	(1.0)	(0.7)	0.2
Gains (losses) recorded related to non-hedge derivatives					4.0	8.1	(1.2)	(0.3)
Gains (losses) recorded related to non-hedge derivatives		(66.5)	7.0
Notional volume of outstanding non-hedge derivative contracts																	885,300,000.0	959,200,000.0	38,083,700,000.0	34,405,700,000.0			713,300,000.0	797,100,000.0	23,063,400,000.0	20,374,000,000.0
Notional volume of outstanding foreign exchange non-hedge derivative contracts, monetary (in Canadian dollars)																					2.6	4.2					2.6	4.2
Value of hedged item																50.0
Amount of debt repaid	325.0															325.0
Interest rate stated percentage																6.90%
Unrealized gain (loss) related to the fair value hedge													(0.9)
Unrealized gain (loss) related to the debt hedged by swap				$ 0.9

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SHORT-TERM DEBT AND LINES OF CREDIT (Tables)

3 Months Ended

Mar. 31, 2012

SHORT-TERM DEBT AND LINES OF CREDIT

Disclosure of outstanding short-term borrowings

(Millions, except percentages)	March 31, 2012			December 31, 2011
Commercial paper outstanding	$	305.5		$	303.3
Average discount rate on outstanding commercial paper	0.34		%	0.31		%

Disclosure of average amount of short-term borrowings outstanding

(Millions)	2012		2011
Average amount of commercial paper outstanding	$	357.5	$	102.7
Average amount of short-term notes payable outstanding	—		10.0

Disclosure of revolving credit facilities and remaining available capacity

(Millions)	Maturity	March 31, 2012		December 31, 2011
Revolving credit facility (Integrys Energy Group)	04/23/13	$	735.0	$	735.0
Revolving credit facility (Integrys Energy Group)	05/17/16	200.0		200.0
Revolving credit facility (Integrys Energy Group)	05/17/14	275.0		275.0
Revolving credit facility (WPS)	04/23/13	115.0		115.0
Revolving credit facility (WPS)	05/17/14	135.0		135.0
Revolving credit facility (PGL)	04/23/13	250.0		250.0
Total short-term credit capacity		$	1,710.0	$	1,710.0
Less:
Letters of credit issued inside credit facilities		$	33.9	$	33.7
Commercial paper outstanding		305.5		303.3
Available capacity under existing agreements		$	1,370.6	$	1,373.0

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FAIR VALUE (Details 5) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Carrying value and estimated fair value of financial instruments
Long-term debt	$ 2,122.1	$ 2,122.0
Preferred stock	51.1	51.1
Carrying Amount
Carrying value and estimated fair value of financial instruments
Long-term debt	2,122.1	2,122.0
Preferred stock	51.1	51.1
Total, Fair value
Carrying value and estimated fair value of financial instruments
Long-term debt	2,272.2	2,281.5
Preferred stock	$ 50.9	$ 51.8

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COMMITMENTS AND CONTINGENCIES (Details 2) (USD $) In Millions, unless otherwise specified		1 Months Ended		1 Months Ended			12 Months Ended	3 Months Ended
	Mar. 31, 2012 EPA settlements with other utilities	Dec. 31, 2011 WDNR Issued NOV's Violation	Mar. 31, 2012 WDNR Issued NOV's Violation	Oct. 31, 2010 Pulliam Title V Air Permit day	Jul. 31, 2010 Columbia Title V Air Permit day	Mar. 31, 2012 Mercury emission MW	Dec. 31, 2005 Sulfur dioxide and nitrogen oxide emissions State	Mar. 31, 2012 Manufactured gas plant remediation site
Environmental remediation obligations
Fines, penalties, and costs of supplemental environmental projects associated with settlements, low end of range	$ 6
Fines, penalties, and costs of supplemental environmental projects associated with settlements, high end of range	30
Number of NOV's alleging violations of the air permits received since 2008			4
Number of NOV's for clerical error received since 2008			1
Number of corrective actions taken for NOV's received			5
Number NOV's dismissed		2
Number of NOV's referred to the state Justice Department		3
Number of days which the EPA reviewed proposed permit				45
Number of days which the EPA directed WDNR to resolve renewal objection					90
Environmental remediation obligations
Percentage mercury reduction from 2002 through 2004 baseline, required by Best Available Control Technology rule in Phase I						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 beginning year 2015, required by Best Available Control Technology rule in Phase II						90.00%
Level of electric generating units above which a reduction in mercury emissions is required by 2015 (in MW)						25
Estimated capital cost to achieve required emission reduction						2
Number of states included in the CAIR regulation							29
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								608.1
Regulatory assets recorded for cash and estimated future remediation expenditures, net of insurance recoveries received								623.7
Insurance recoveries received								59.9
Cash expenditures for environmental remediation not yet recovered in rates								$ 15.6

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SEGMENTS OF BUSINESS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 segment	Mar. 31, 2011
Segment Reporting Information
Number of reportable segments	5
External revenues	$ 1,251.3	$ 1,627.1
Depreciation and amortization expense	62.7	62.3
Earnings in equity method investments	21.1	19.4
Miscellaneous income	2.4	1.8
Interest expense	30.5	34.8
Provision (benefit) for income taxes	46.8	71.7
Net income (loss) from continuing operations	97.8	123.4
Discontinued operations, net of tax	1.9	0.1
Preferred stock dividends of subsidiary	(0.8)	(0.8)
Net income (loss) attributed to common shareholders	98.9	122.7
ATC
Segment Reporting Information
Equity method investment, ownership interest (as a percent)	34.00%
Earnings in equity method investments	20.8	19.2
Holding Company and Other
Segment Reporting Information
Discontinued operations, net of tax	1.9
Reconciling Eliminations
Segment Reporting Information
Intersegment revenues	(2.6)	(8.0)
Depreciation and amortization expense	(0.1)	(0.1)
Miscellaneous income	(4.2)	(5.5)
Interest expense	(4.2)	(5.5)
Regulated Operations
Segment Reporting Information
External revenues	971.0	1,168.7
Intersegment revenues	1.7	7.3
Depreciation and amortization expense	54.4	53.3
Earnings in equity method investments	20.8	19.2
Miscellaneous income	0.3	0.4
Interest expense	21.2	24.4
Provision (benefit) for income taxes	69.2	71.8
Net income (loss) from continuing operations	117.0	114.5
Preferred stock dividends of subsidiary	(0.8)	(0.8)
Net income (loss) attributed to common shareholders	116.2	113.7
Regulated Operations | Natural Gas Utility
Segment Reporting Information
External revenues	664.0	851.3
Intersegment revenues	1.7	2.1
Depreciation and amortization expense	32.4	31.2
Miscellaneous income	0.2	0.1
Interest expense	12.0	12.4
Provision (benefit) for income taxes	51.5	52.2
Net income (loss) from continuing operations	78.7	77.4
Preferred stock dividends of subsidiary	(0.1)	(0.2)
Net income (loss) attributed to common shareholders	78.6	77.2
Regulated Operations | Electric Utility
Segment Reporting Information
External revenues	307.0	317.4
Intersegment revenues		5.2
Depreciation and amortization expense	22.0	22.1
Miscellaneous income	0.1	0.3
Interest expense	9.2	12.0
Provision (benefit) for income taxes	10.2	11.8
Net income (loss) from continuing operations	25.0	25.7
Preferred stock dividends of subsidiary	(0.7)	(0.6)
Net income (loss) attributed to common shareholders	24.3	25.1
Regulated Operations | Electric Transmission Investment
Segment Reporting Information
Earnings in equity method investments	20.8	19.2
Provision (benefit) for income taxes	7.5	7.8
Net income (loss) from continuing operations	13.3	11.4
Net income (loss) attributed to common shareholders	13.3	11.4
Nonutility and Nonregulated Operations | Integrys Energy Services
Segment Reporting Information
External revenues	272.8	455.2
Intersegment revenues	0.2	0.3
Depreciation and amortization expense	2.9	3.3
Earnings in equity method investments	0.1
Miscellaneous income	0.6	0.9
Interest expense	0.6	0.5
Provision (benefit) for income taxes	(12.9)	5.6
Net income (loss) from continuing operations	(20.1)	10.7
Discontinued operations, net of tax		0.1
Net income (loss) attributed to common shareholders	(20.1)	10.8
Nonutility and Nonregulated Operations | Holding Company and Other
Segment Reporting Information
External revenues	7.5	3.2
Intersegment revenues	0.7	0.4
Depreciation and amortization expense	5.5	5.8
Earnings in equity method investments	0.2	0.2
Miscellaneous income	5.7	6.0
Interest expense	12.9	15.4
Provision (benefit) for income taxes	(9.5)	(5.7)
Net income (loss) from continuing operations	0.9	(1.8)
Discontinued operations, net of tax	1.9
Net income (loss) attributed to common shareholders	$ 2.8	$ (1.8)

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FAIR VALUE (Details 3) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 USDpermegawattmonth
FTRs
Significant internally-developed unobservable inputs
Fair Value, Assets	1.0
Fair Value, Liabilities	0.1
FTRs | Weighted Average | Market-based
Significant internally-developed unobservable inputs
Forward market prices	170.36
Coal contract
Significant internally-developed unobservable inputs
Fair Value, Liabilities	13.4
Coal contract | Maximum | Market-based
Significant internally-developed unobservable inputs
Forward market prices	15.1
Coal contract | Minimum | Market-based
Significant internally-developed unobservable inputs
Forward market prices	14.6
Natural gas contracts
Significant internally-developed unobservable inputs
Fair Value, Assets	11.1
Fair Value, Liabilities	0.2
Natural gas contracts | Maximum | Market-based
Significant internally-developed unobservable inputs
Forward market prices	1.54
Probability of default (as a percent)	50.99%
Natural gas contracts | Minimum | Market-based
Significant internally-developed unobservable inputs
Forward market prices	(0.04)
Probability of default (as a percent)	11.62%
Electric contracts
Significant internally-developed unobservable inputs
Fair Value, Assets	14.1
Fair Value, Liabilities	36.0
Electric contracts | Maximum | Market-based
Significant internally-developed unobservable inputs
Forward market prices	9.79
Option volatilities (as a percent)	59.51%
Monthly curve shaping (as a percent)	(11.57%)
Electric contracts | Minimum | Market-based
Significant internally-developed unobservable inputs
Forward market prices	(6.05)
Option volatilities (as a percent)	19.99%
Monthly curve shaping (as a percent)	(15.03%)

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ADVERTISING COSTS

3 Months Ended

Mar. 31, 2012

ADVERTISING COSTS

ADVERTISING COSTS

NOTE 18—ADVERTISING COSTS

At March 31, 2012, 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. The asset balances for each of the direct-response advertising cost pools are reviewed quarterly for impairment. Capitalized direct-response advertising costs, net of accumulated amortization, totaled $4.4 million as of March 31, 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 $1.0 million for the quarter ended March 31, 2012. There was no amortization of direct-response advertising costs for the quarter ended March 31, 2011.

We expense all advertising costs as incurred, except for those capitalized as direct-response advertising. Other advertising expense was $1.7 million and $1.9 million for the quarters ended March 31, 2012 and 2011, respectively.

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INVESTMENT IN ATC (Details 2) (ATC, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
ATC
Income statement data
Revenues	$ 147.7	$ 139.6
Operating expenses	69.6	63.1
Other expense	20.0	22.3
Net income	58.1	54.2
Balance sheet data
Current assets	57.1		58.7
Noncurrent assets	3,099.0		3,053.7
Total assets	3,156.1		3,112.4
Current liabilities	314.5		298.5
Long-term debt	1,400.0		1,400.0
Other noncurrent liabilities	88.1		82.6
Members' equity	1,353.5		1,331.3
Total liabilities and members' equity	$ 3,156.1		$ 3,112.4

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CASH AND CASH EQUIVALENTS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 month	Mar. 31, 2011
CASH AND CASH EQUIVALENTS
Maximum term of original maturity to classify instruments as cash equivalent (in months)	3
Supplemental disclosure of statements of cash flows
Cash paid for interest	$ 8.9	$ 20.1
Cash (received) paid for income taxes	(33.2)	2.9
Significant noncash transactions
Construction costs funded through accounts payable	50.2	9.4
Equity issued for stock-based compensation plans		6.6
Equity issued for reinvested dividends		$ 5.4

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REGULATORY ENVIRONMENT (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended												3 Months Ended			12 Months Ended		3 Months Ended		3 Months Ended						1 Months Ended	16 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 30, 2012 Public Service Commission of Wisconsin (PSCW) 2013 Rate Case Entity's Original Request	Mar. 31, 2012 Public Service Commission of Wisconsin (PSCW) 2012 Rates Rate Order	Jan. 13, 2011 Public Service Commission of Wisconsin (PSCW) 2011 Rates Rate Order	Mar. 30, 2012 Public Service Commission of Wisconsin (PSCW) Natural Gas Rate Case 2013 Rate Case Entity's Original Request	Jan. 13, 2011 Public Service Commission of Wisconsin (PSCW) Natural Gas Rate Case 2011 Rates Rate Order	Dec. 09, 2011 Public Service Commission of Wisconsin (PSCW) Natural Gas Rate Case 2012 Rate Case Rate Order	Mar. 30, 2012 Public Service Commission of Wisconsin (PSCW) Retail Electric Rate Case 2013 Rate Case Entity's Original Request	Dec. 09, 2011 Public Service Commission of Wisconsin (PSCW) Retail Electric Rate Case 2012 Rates Rate Order	Jan. 13, 2011 Public Service Commission of Wisconsin (PSCW) Retail Electric Rate Case 2011 Rates Rate Order	Dec. 09, 2011 Public Service Commission of Wisconsin (PSCW) Retail Electric Rate Case 2012 Rate Case Rate Order	Mar. 31, 2012 Michigan Public Service Commission (MPSC) - UPPCO Retail Electric Rate Case 2012 Rates Rate Order	Dec. 20, 2011 Michigan Public Service Commission (MPSC) - UPPCO Retail Electric Rate Case 2012 Rates Rate Order	Dec. 21, 2010 Michigan Public Service Commission (MPSC) - UPPCO Retail Electric Rate Case 2011 Rates Rate Order	Dec. 31, 2011 Illinois Commerce Commission (ICC) - PGL Natural Gas Rate Case Rider ICR year	Jun. 30, 2010 Illinois Commerce Commission (ICC) - PGL Natural Gas Rate Case Rider ICR	Mar. 31, 2012 Illinois Commerce Commission (ICC) - PGL Natural Gas Rate Case 2012 Rates Rate Order	Jan. 10, 2012 Illinois Commerce Commission (ICC) - PGL Natural Gas Rate Case 2012 Rates Rate Order	Mar. 31, 2012 Illinois Commerce Commission (ICC) - NSG Natural Gas Rate Case 2012 Rates Rate Order	Feb. 23, 2012 Illinois Commerce Commission (ICC) - NSG Natural Gas Rate Case 2012 Rates Rate Order interveners	Jan. 10, 2012 Illinois Commerce Commission (ICC) - NSG Natural Gas Rate Case 2012 Rates Rate Order	Nov. 30, 2010 Minnesota Public Utilities Commission (MPUC) Natural Gas Rate Case 2011 Rates Entity's Original Request	Jan. 28, 2011 Minnesota Public Utilities Commission (MPUC) Natural Gas Rate Case 2011 Rates Interim Rate Order	Apr. 02, 2012 Minnesota Public Utilities Commission (MPUC) Natural Gas Rate Case 2011 Rates Regulatory Authority Staff Recommendation	May 31, 2010 Federal Energy Regulatory Commission (FERC) Seams Elimination Charge Adjustment (SECA) Integrys Energy Services issue	Mar. 31, 2006 Federal Energy Regulatory Commission (FERC) Seams Elimination Charge Adjustment (SECA) Integrys Energy Services month	Mar. 31, 2012 Federal Energy Regulatory Commission (FERC) Seams Elimination Charge Adjustment (SECA) Integrys Energy Services
Regulatory Proceedings:
Rate increase (decrease)									$ 85.1
Natural gas rate increase						12.8																	15.2
Percent return on equity			10.30%																				11.25%
Equity ratio percent			52.37%																				50.20%
Rate increase (decrease)							(8.3)	(7.2)											57.8			1.9		7.5
Electric rate increase										8.1	21.0			4.2	8.9
Expenses related to electric decoupling													1.5
Deferred costs related to CSAPR				1.3
Recovery of prior deferral							7.1				20.0
Estimated fuel refund including carrying costs											15.2																	3.8
Percent return on equity					10.30%									10.20%	10.30%				9.45%			9.45%		10.21%
Authorized rate of return on common equity in the previous rate order (as a percent)					10.90%
Equity ratio percent					51.65%									54.90%	54.86%				49.00%			50.00%		50.20%
Number of interveners that filed appeals of the rate order																					2
Regulatory assets of pending future recovery	(9.5)	(13.5)																12.0		1.0
Percentage of price variance from the cost of fuel and purchased power included in rates											2.00%	2.00%
Period of AMRP project (in years)																20
Proposed annual baseline																	45.28
Transition period when charges paid (in months)																											16
Billings received																											19.2
Favorable rulings, number of issues																										2
Rate increase (decrease)																									$ 10.7
Percent return on equity (as a percent)																									9.41%
Equity ratio percent																									50.48%

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EMPLOYEE BENEFIT PLANS (Tables)

3 Months Ended

Mar. 31, 2012

EMPLOYEE BENEFIT PLANS

Components of net periodic benefit cost

	Pension Benefits						Other Postretirement Benefits
(Millions)	2012			2011			2012			2011
Service cost	$	12.4		$	11.3		$	5.5		$	5.0
Interest cost	19.8			20.5			7.2			7.7
Expected return on plan assets	(27.1		)	(24.7		)	(7.0		)	(5.0		)
Amortization of transition obligation	—			—			0.1			0.1
Amortization of prior service cost (credit)	1.2			1.3			(0.9		)	(0.9		)
Amortization of net actuarial loss	8.3			4.7			1.6			1.1
Net periodic benefit cost	$	14.6		$	13.1		$	6.5		$	8.0

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SHORT-TERM DEBT AND LINES OF CREDIT (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Short-term borrowings
Short-term borrowings outstanding	$ 305.5		$ 303.3
Commercial paper
Short-term borrowings
Short-term borrowings outstanding	305.5		303.3
Average discount rate (as a percent)	0.34%		0.31%
Average amount of short-term borrowings outstanding	357.5	102.7
Short-term notes payable
Short-term borrowings
Average amount of short-term borrowings outstanding		$ 10.0

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COMMON EQUITY (Details 5) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Capital Transactions with Subsidiaries
Dividends To Parent	$ 43.1
Return Of Capital To Parent	26.5
Equity Contributions From Parent	51.9
WPS Investments, LLC
Capital Transactions with Subsidiaries
Dividends To Parent	16.7
Equity Contributions From Parent	3.4
WPS
Capital Transactions with Subsidiaries
Dividends To Parent	26.4
Equity Contributions From Parent	40.0
WPS | WPS Investments, LLC
Capital Transactions with Subsidiaries
Ownership interest (as a percent)	12.17%
MERC
Capital Transactions with Subsidiaries
Return Of Capital To Parent	15.0
IBS
Capital Transactions with Subsidiaries
Return Of Capital To Parent	3.0
MGU
Capital Transactions with Subsidiaries
Return Of Capital To Parent	6.0
UPPCO
Capital Transactions with Subsidiaries
Return Of Capital To Parent	2.5
Equity Contributions From Parent	$ 8.5
UPPCO | WPS Investments, LLC
Capital Transactions with Subsidiaries
Ownership interest (as a percent)	2.59%

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STOCK-BASED COMPENSATION (Details 2) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 year
STOCK-BASED COMPENSATION
Cash received from option exercises (in dollars)	$ 10.1
Stock Options
Outstanding, at the beginning of the period (in shares)	2,953,630
Granted (in shares)	279,535
Exercised (in shares)	(225,986)
Outstanding at the end of the period (in shares)	3,007,179
Exercisable at the end of the period (in shares)	2,221,968
Weighted-Average Exercise Price
Outstanding at the beginning of the period (in dollars per share)	$ 48.09
Granted (in dollars per share)	$ 53.24
Exercised (in dollars per share)	$ 44.83
Outstanding at the end of the period (in dollars per share)	$ 48.82
Exercisable at the end of the period (in dollars per share)	$ 49.24
Weighted-Average Remaining Contractual Term (in years)
Outstanding at the end of the period (in years)	5.97
Exercisable at the end of the period (in years)	5.02
Aggregate Intrinsic Value
Outstanding at the end of the period (in dollars)	14.2
Exercisable at the end of the period (in dollars)	$ 9.9

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RISK MANAGEMENT ACTIVITIES (Details 5) (Cash flow hedges, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Nonregulated revenue
Risk management activities
Gain (loss) Reclassified from AOCI into income	$ (0.3)	$ (13.3)
Gain Recognized in Income on Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing)		1.1
Natural gas contracts | Nonregulated revenue
Risk management activities
Gain Recognized in Income on Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing)		0.8
Electric contracts | Nonregulated revenue
Risk management activities
Gain Recognized in Income on Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing)		0.3
Nonregulated Segments
Risk management activities
Unrealized Gain (Loss) Recognized in OCI of Derivative Instruments (Effective Portion)		(3.4)
Nonregulated Segments | Natural gas contracts
Risk management activities
Unrealized Gain (Loss) Recognized in OCI of Derivative Instruments (Effective Portion)		1.2
Nonregulated Segments | Natural gas contracts | Nonregulated revenue
Risk management activities
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)		(8.6)
Gain (Loss) Reclassified from Accumulated OCI into Income (Hedge Designation Discontinued)		(0.3)
Nonregulated Segments | Electric contracts
Risk management activities
Unrealized Gain (Loss) Recognized in OCI of Derivative Instruments (Effective Portion)		(4.6)
Nonregulated Segments | Electric contracts | Nonregulated revenue
Risk management activities
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)		(4.1)
Nonregulated Segments | Interest rate swaps | Interest expense.
Risk management activities
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	$ (0.3)	$ (0.3)

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CASH AND CASH EQUIVALENTS

3 Months Ended

Mar. 31, 2012

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 supplemental disclosure to our statements of cash flows:

	Three Months Ended March 31
(Millions)	2012			2011
Cash paid for interest	$	8.9		$	20.1
Cash (received) paid for income taxes	(33.2		)	2.9

Significant noncash transactions were:

	Three Months Ended March 31
(Millions)	2012		2011
Construction costs funded through accounts payable	$	50.2	$	9.4
Equity issued for stock-based compensation plans	—		6.6
Equity issued for reinvested dividends	—		5.4

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STOCK-BASED COMPENSATION (Details 3) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 year	Mar. 31, 2011
Stock Options
Information related to Share based awards
Intrinsic value of options exercised	$ 2.0	$ 0.6
Period of historical volatility used to estimate expected volatility (in years)	10
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)	$ 6.30
Expected term (in years)	5
Risk-free interest rate, low end of range (as a percent)	0.17%
Risk-free interest rate, high end of range (as a percent)	2.18%
Expected dividend yield (as a percent)	5.28%
Expected volatility (as a percent)	25.00%
Additional disclosures
Compensation cost not yet recognized	2.6
Period over which compensation cost is to be recognized (in years)	3.2
Performance Stock Rights
Weighted-average fair values per stock option along with the assumptions incorporated into the valuation models
Risk-free interest rate, low end of range (as a percent)	0.32%
Risk-free interest rate, high end of range (as a percent)	1.27%
Expected volatility, low end of range (as a percent)	21.00%
Expected volatility, high end of range (as a percent)	36.00%
Additional disclosures
Compensation cost not yet recognized	5.7
Period over which compensation cost is to be recognized (in years)	2.3
Tax benefit realized from the distribution of shares	1.9	2.5
Total intrinsic value
Total intrinsic value of performance stock rights distributed during the period	4.7	6.3
Performance Stock Rights | Minimum
Information related to Share based awards
Period of historical volatility used to estimate expected volatility (in years)	1
Weighted-average fair values per stock option along with the assumptions incorporated into the valuation models
Expected dividend yield (as a percent)	5.28%
Performance Stock Rights | Maximum
Information related to Share based awards
Period of historical volatility used to estimate expected volatility (in years)	3
Weighted-average fair values per stock option along with the assumptions incorporated into the valuation models
Expected dividend yield (as a percent)	5.34%
Restricted Shares and Restricted Share Units
Additional disclosures
Compensation cost not yet recognized	16.7
Period over which compensation cost is to be recognized (in years)	3.1
Tax benefit realized from the distribution of shares	4.2	2.5
Performance Stock Rights, Restricted Shares and Restricted Stock Units Activity
Outstanding at the beginning of the period (in shares)	497,722
Granted (in shares)	188,346
Dividend equivalents (in shares)	6,821
Vested (in shares)	(193,878)
Forfeited (in shares)	(1,440)
Outstanding at the end of period (in shares)	497,571
Total intrinsic value
Total intrinsic value of awards vested	$ 10.4	$ 6.3
Weighted-Average Date Fair Value
Outstanding at the beginning of the period (in dollars per share)	$ 45.21
Granted (in dollars per share)	$ 53.24	$ 49.40
Dividend equivalents (in dollars per share)	$ 47.94
Vested (in dollars per share)	$ 45.07
Forfeited (in dollars per share)	$ (46.48)
Outstanding at the end of the period (in dollars per share)	$ 48.39
Performance Stock Rights accounted for as Equity awards
Performance Stock Rights, Restricted Shares and Restricted Stock Units Activity
Outstanding at the beginning of the period (in shares)	135,948
Granted (in shares)	18,865
Distributed (in shares)	(70,598)
Adjustment for final payout (in shares)	(24,804)
Outstanding at the end of period (in shares)	59,411
Weighted-Average Date Fair Value
Outstanding at the beginning of the period (in dollars per share)	$ 46.18
Granted (in dollars per share)	$ 52.70
Distributed (in dollars per share)	$ 42.93
Adjustment for final payout (in dollars per shares)	$ 42.93
Outstanding at the end of the period (in dollars per share)	$ 53.48
Period prior to the end of the performance period during which employees cannot change their election to defer the value of award into deferred compensation plan	6
Performance Stock Rights accounted as Liability awards
Performance Stock Rights, Restricted Shares and Restricted Stock Units Activity
Outstanding at the beginning of the period (in shares)	186,215
Granted (in shares)	75,408
Distributed (in shares)	(16,001)
Adjustment for final payout (in shares)	(5,622)
Outstanding at the end of period (in shares)	240,000
Weighted-Average Date Fair Value
Outstanding at the end of the period (in dollars per share)	$ 56.22

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RISK MANAGEMENT ACTIVITIES (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Derivative assets and liabilities from risk management activities
Current Assets from Risk Management Activities	$ 266.2	$ 227.2
Long-term Assets from Risk Management Activities	56.6	64.4
Current Liabilities from Risk Management Activities	400.0	311.6
Long-term Liabilities from Risk Management Activities	109.9	102.0
Risk Management Assets	322.8	291.6
Risk Management Liabilities	509.9	413.6
Cash collateral provided to others	64.2	50.9
Cash collateral received from others	1.8	2.3
Utility Segments | Cash flow hedges | Natural gas contracts
Derivative assets and liabilities from risk management activities
Current Liabilities from Risk Management Activities	1.2	0.9
Long-term Liabilities from Risk Management Activities	0.2	0.2
Utility Segments | Non-hedge derivatives | Natural gas contracts
Derivative assets and liabilities from risk management activities
Current Assets from Risk Management Activities	5.2	9.1
Long-term Assets from Risk Management Activities	0.3	0.1
Current Liabilities from Risk Management Activities	43.9	35.4
Long-term Liabilities from Risk Management Activities	9.2	8.2
Utility Segments | Non-hedge derivatives | FTRs
Derivative assets and liabilities from risk management activities
Current Assets from Risk Management Activities	1.0	2.3
Current Liabilities from Risk Management Activities	0.1	0.1
Utility Segments | Non-hedge derivatives | Petroleum product contracts
Derivative assets and liabilities from risk management activities
Current Assets from Risk Management Activities	0.4	0.1
Utility Segments | Non-hedge derivatives | Coal contract
Derivative assets and liabilities from risk management activities
Current Liabilities from Risk Management Activities	5.6	2.5
Long-term Liabilities from Risk Management Activities	7.8	4.4
Nonregulated Segments | Non-hedge derivatives | Natural gas contracts
Derivative assets and liabilities from risk management activities
Current Assets from Risk Management Activities	121.2	121.6
Long-term Assets from Risk Management Activities	22.3	41.9
Current Liabilities from Risk Management Activities	120.4	120.5
Long-term Liabilities from Risk Management Activities	20.7	40.5
Nonregulated Segments | Non-hedge derivatives | Electric contracts
Derivative assets and liabilities from risk management activities
Current Assets from Risk Management Activities	138.2	93.9
Long-term Assets from Risk Management Activities	34.0	22.4
Current Liabilities from Risk Management Activities	228.6	152.0
Long-term Liabilities from Risk Management Activities	72.0	48.7
Nonregulated Segments | Non-hedge derivatives | Foreign exchange contracts
Derivative assets and liabilities from risk management activities
Current Assets from Risk Management Activities	0.2	0.2
Current Liabilities from Risk Management Activities	$ 0.2	$ 0.2

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CASH AND CASH EQUIVALENTS (Tables)

3 Months Ended

Mar. 31, 2012

CASH AND CASH EQUIVALENTS

Schedule of supplemental disclosure to statements of cash flows

	Three Months Ended March 31
(Millions)	2012			2011
Cash paid for interest	$	8.9		$	20.1
Cash (received) paid for income taxes	(33.2		)	2.9

Schedule of significant noncash transactions

	Three Months Ended March 31
(Millions)	2012		2011
Construction costs funded through accounts payable	$	50.2	$	9.4
Equity issued for stock-based compensation plans	—		6.6
Equity issued for reinvested dividends	—		5.4

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NEW ACCOUNTING PRONOUNCEMENTS

3 Months Ended

Mar. 31, 2012

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS

NOTE 21—NEW ACCOUNTING PRONOUNCEMENTS

Recently Adopted Accounting Guidance

We adopted ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS).”  The amendments change the wording used to describe the requirements for measuring fair value and also require new disclosures about fair value measurements. The amendments also clarify the intent concerning the application of existing fair value measurement requirements. Adoption of this new guidance resulted in new disclosures in Note 17, “Fair Value,” but did not affect our fair value measurements.

We adopted ASU 2011-05, “Presentation of Comprehensive Income,” and ASU 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05.” The guidance requires that the total of comprehensive income, the components of net income, and the components of OCI be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. We elected to include a separate statement of comprehensive income.

ASU 2011-08, “Testing Goodwill for Impairment,” was effective January 1, 2012. The amendments give companies an option to first perform a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If a company concludes that this is the case, the 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 in the first quarter of 2012.

Recently Issued Accounting Guidance Not Yet Effective

ASU 2011-11, “Disclosures about Offsetting Assets and Liabilities,” was issued in December 2011. The guidance requires enhanced disclosures about offsetting and related arrangements. This guidance is effective for our reporting period ending March 31, 2013. Management is currently evaluating the impact that the adoption of this standard will have on our financial statements.

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COMMITMENTS AND CONTINGENCIES (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Coal supply and transportation | Electric Utility
Purchase and sales commitments
Long-term purchase and sale commitments	$ 186.3
Purchased power | Electric Utility
Purchase and sales commitments
Long-term purchase and sale commitments	1,213.9
Other commodities | Electric Utility
Purchase and sales commitments
Long-term purchase and sale commitments	5.4
Natural gas supply and transportation | Natural Gas Utility
Purchase and sales commitments
Long-term purchase and sale commitments	836.7
Electricity and natural gas supply | Integrys Energy Services
Purchase and sales commitments
Long-term purchase and sale commitments	218.9
Purchase orders
Purchase and sales commitments
Supply contract obligation amount	$ 536.1

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RISK MANAGEMENT ACTIVITIES (Details 2) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Integrys Energy Services.
Risk management activities
Aggregate fair value of credit-risk derivative instruments	$ 231.4	$ 193.8
Collateral that would have been required:	281.7	272.3
Collateral already satisfied, Letters of credit	11.0	11.0
Collateral remaining:	270.7	261.3
Utility Segments
Risk management activities
Aggregate fair value of credit-risk derivative instruments	52.9	39.1
Collateral that would have been required:	42.5	28.7
Collateral remaining:	$ 42.5	$ 28.7

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RISK MANAGEMENT ACTIVITIES (Tables)

3 Months Ended

Mar. 31, 2012

RISK MANAGEMENT ACTIVITIES

Assets and liabilities from risk management activities

	March 31, 2012
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Utility Segments
Non-hedge derivatives
Natural gas contracts	Current	$	5.2	$	43.9
Natural gas contracts	Long-term	0.3		9.2
Financial transmission rights (FTRs)	Current	1.0		0.1
Petroleum product contracts	Current	0.4		—
Coal contract	Current	—		5.6
Coal contract	Long-term	—		7.8
Cash flow hedges
Natural gas contracts	Current	—		1.2
Natural gas contracts	Long-term	—		0.2
Nonregulated Segments
Non-hedge derivatives
Natural gas contracts	Current	121.2		120.4
Natural gas contracts	Long-term	22.3		20.7
Electric contracts	Current	138.2		228.6
Electric contracts	Long-term	34.0		72.0
Foreign exchange contracts	Current	0.2		0.2
	Current	266.2		400.0
	Long-term	56.6		109.9
Total		$	322.8	$	509.9

*All derivatives are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and sales exception. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

		December 31, 2011
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Utility Segments
Non-hedge derivatives
Natural gas contracts	Current	$	9.1	$	35.4
Natural gas contracts	Long-term	0.1		8.2
FTRs	Current	2.3		0.1
Petroleum product contracts	Current	0.1		—
Coal contract	Current	—		2.5
Coal contract	Long-term	—		4.4
Cash flow hedges
Natural gas contracts	Current	—		0.9
Natural gas contracts	Long-term	—		0.2
Nonregulated Segments
Non-hedge derivatives
Natural gas contracts	Current	121.6		120.5
Natural gas contracts	Long-term	41.9		40.5
Electric contracts	Current	93.9		152.0
Electric contracts	Long-term	22.4		48.7
Foreign exchange contracts	Current	0.2		0.2
	Current	227.2		311.6
	Long-term	64.4		102.0
Total		$	291.6	$	413.6

*All derivatives are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and sales exception. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

Cash collateral positions

(Millions)	March 31, 2012		December 31, 2011
Cash collateral provided to others	$	64.2	$	50.9
Cash collateral received from others *	1.8		2.3

*Reflected in other current liabilities on the balance sheets.

Credit risk derivatives in a liability position

(Millions)	March 31, 2012		December 31, 2011
Integrys Energy Services	$	231.4	$	193.8
Utility segments	52.9		39.1

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

(Millions)	March 31, 2012		December 31, 2011
Collateral that would have been required:
Integrys Energy Services	$	281.7	$	272.3
Utility segments	42.5		28.7
Collateral already satisfied:
Integrys Energy Services — Letters of credit	11.0		11.0
Collateral remaining:
Integrys Energy Services	270.7		261.3
Utility segments	42.5		28.7

Utility Segments, Notional volumes of outstanding non-hedge derivative contracts

	March 31, 2012			December 31, 2011
	Purchases	Sales	Other Transactions	Purchases	Other Transactions
Natural gas (millions of therms)	755.5	0.3	N/A	1,122.7	N/A
FTRs (millions of kilowatt-hours)	N/A	N/A	1,911.0	N/A	5,077.5
Petroleum products (barrels)	51,872.0	N/A	N/A	46,872.0	N/A
Coal contract (millions of tons)	3.9	N/A	N/A	4.1	N/A

Utility Segments, Unrealized gains (losses) related to non-hedge derivatives at the utilities

		Three Months Ended March 31
(Millions)	Financial Statement Presentation	2012			2011
Natural gas contracts	Balance Sheet — Regulatory assets (current)	$	(6.4	)	$	11.2
Natural gas contracts	Balance Sheet — Regulatory assets (long-term)	(0.8		)	1.6
Natural gas contracts	Balance Sheet — Regulatory liabilities (current)	(3.7		)	(0.1		)
Natural gas contracts	Balance Sheet — Regulatory liabilities (long-term)	0.1			0.1
Natural gas contracts	Income Statement — Utility cost of fuel, natural gas, and purchased power	0.1			0.1
FTRs	Balance Sheet — Regulatory assets (current)	0.4			0.1
FTRs	Balance Sheet — Regulatory liabilities (current)	(0.3		)	(1.2		)
Petroleum product contracts	Balance Sheet — Regulatory assets (current)	0.1			—
Petroleum product contracts	Balance Sheet — Regulatory liabilities (current)	0.1			0.4
Petroleum product contracts	Income Statement — Operating and maintenance expense	0.1			0.5
Coal contract	Balance Sheet — Regulatory assets (current)	(3.1		)	(0.5		)
Coal contract	Balance Sheet — Regulatory assets (long-term)	(3.5		)	(3.2		)
Coal contract	Balance Sheet — Regulatory liabilities (long-term)	—			(3.7		)

Nonregulated Segments, Notional volumes of outstanding non-hedge derivative contracts

	March 31, 2012		December 31, 2011
(Millions)	Purchases	Sales	Purchases	Sales
Commodity contracts
Natural gas (therms)	885.3	713.3	959.2	797.1
Electric (kilowatt-hours)	38,083.7	23,063.4	34,405.7	20,374.0
Foreign exchange contracts (Canadian dollars)	2.6	2.6	4.2	4.2

Nonregulated Segments, gains (losses) related to non-hedge derivatives

		Three Months Ended March 31
(Millions)	Income Statement Presentation	2012			2011
Natural gas contracts	Nonregulated revenue	$	4.0		$	8.1
Natural gas contracts	Nonregulated revenue (reclassified from accumulated OCI) *	(1.2		)	(0.3		)
Electric contracts	Nonregulated revenue	(68.6		)	(1.0		)
Electric contracts	Nonregulated revenue (reclassified from accumulated OCI) *	(0.7		)	0.2
Total		$	(66.5	)	$	7.0

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

Nonregulated Segments, Fair value hedges unrealized gains (losses)

		Three Months Ended
(Millions)	Income Statement Presentation	March 31, 2011
Interest rate swap	Interest expense	$	(0.9	)
Debt hedged by swap	Interest expense	0.9
Total		$	—

Nonregulated Segments, Cash flow hedges recorded in OCI and in earnings

Unrealized Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
(Millions)	Three Months Ended March 31, 2011
Natural gas contracts	$	1.2
Electric contracts	(4.6		)
Total	$	(3.4	)

Nonregulated Segments, Cash flow hedges reclassified from Accumulated Other Comprehensive Income into Income

Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
		Three Months Ended March 31
(Millions)	Income Statement Presentation	2012			2011
Settled/Realized
Natural gas contracts	Nonregulated revenue	$	—		$	(8.6	)
Electric contracts	Nonregulated revenue	—			(4.1		)
Interest rate swaps *	Interest expense	(0.3		)	(0.3		)
Hedge Designation Discontinued
Natural gas contracts	Nonregulated revenue	—			(0.3		)
Total		$	(0.3	)	$	(13.3	)

*In May 2010, we entered into interest rate swaps that were designated as cash flow hedges to hedge the variability in forecasted interest payments on a debt issuance. These swaps were terminated when the related debt was issued in November 2010. Amounts remaining in accumulated OCI are being reclassified to interest expense over the life of the related debt.

Nonregulated Segments, Cash flow hedges recorded in OCI (Ineffective Portion and Amount Excluded from Effectiveness Testing)

Gain Recognized in Income on Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing)
(Millions)	Income Statement Presentation	Three Months Ended March 31, 2011
Natural gas contracts	Nonregulated revenue	$	0.8
Electric contracts	Nonregulated revenue	0.3
Total		$	1.1

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INVESTMENT IN ATC (Tables) (ATC)

3 Months Ended

Mar. 31, 2012

ATC

Schedule of Equity Method Investments

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

	Three Months Ended March 31
(Millions)	2012		2011
Balance at the beginning of period	$	439.4	$	416.3
Add: Equity in net income	20.8		19.2
Add: Capital contributions	3.4		3.4
Less: Dividends received	16.7		16.2
Balance at the end of period	$	446.9	$	422.7

Summarized income statement information of ATC

	Three Months Ended March 31
(Millions)	2012		2011
Income statement data
Revenues	$	147.7	$	139.6
Operating expenses	69.6		63.1
Other expense	20.0		22.3
Net income *	$	58.1	$	54.2

*As most income taxes are the responsibility of its members, ATC does not report a provision for its members’ income taxes in its income statements.

Summarized balance sheet information of ATC

(Millions)	March 31, 2012		December 31, 2011
Balance sheet data
Current assets	$	57.1	$	58.7
Noncurrent assets	3,099.0		3,053.7
Total assets	$	3,156.1	$	3,112.4
Current liabilities	$	314.5	$	298.5
Long-term debt	1,400.0		1,400.0
Other noncurrent liabilities	88.1		82.6
Members’ equity	1,353.5		1,331.3
Total liabilities and members’ equity	$	3,156.1	$	3,112.4

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FINANCIAL INFORMATION

3 Months Ended

Mar. 31, 2012

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, 2011.

In management’s opinion, these unaudited financial statements include all adjustments considered 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.

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GOODWILL AND OTHER INTANGIBLE ASSETS (Tables)

3 Months Ended

Mar. 31, 2012

GOODWILL AND OTHER INTANGIBLE ASSETS

Identifiable intangible assets other than goodwill

(Millions)	March 31, 2012							December 31, 2011
	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets
Customer-related (1)	$	34.5	$	(25.4	)	$	9.1	$	34.5	$	(24.8	)	$	9.7
Electric contract assets (2)	—		—			—		7.8		(6.6		)	1.2
Patents (3)	7.2		(0.1		)	7.1		7.2		—			7.2
Compressed natural gas fueling contract assets (4)	5.6		(0.6		)	5.0		5.6		(0.3		)	5.3
Renewable energy credits (5)	3.3		—			3.3		2.8		—			2.8
Nonregulated easements (6)	3.8		(0.7		)	3.1		3.8		(0.7		)	3.1
Customer-owned equipment modifications (7)	3.8		(0.3		)	3.5		3.6		(0.2		)	3.4
Emission allowances (8)	1.6		(0.1		)	1.5		1.7		(0.2		)	1.5
Other	0.8		(0.3		)	0.5		1.4		(0.3		)	1.1
Total	$	60.6	$	(27.5	)	$	33.1	$	68.4	$	(33.1	)	$	35.3
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	$	70.8	$	(27.5	)	$	43.3	$	78.6	$	(33.1	)	$	45.5

(1)Includes customer relationship assets associated with PELLC’s former nonregulated retail natural gas and electric operations, MERC’s nonutility ServiceChoice business, 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, 2012, was approximately 10 years.

(2)Represents electric customer contracts acquired in exchange for risk management assets.

(3)Includes the fair value of patents at Pinnacle related to a system for more efficiently compressing natural gas to allow for faster fueling. The remaining amortization period at March 31, 2012, was approximately 18 years.

(4)Represents the fair value of Trillium and Pinnacle compressed natural gas customer fueling contracts acquired in September 2011. The remaining amortization period at March 31, 2012, was approximately 9 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, 2012, of approximately 12 years.

(7)Relates to modifications to customer-owned equipment that allow the end-use customer of a pipeline to accept landfill gas. These intangible assets are amortized on a straight-line basis, with a remaining weighted-average amortization period at March 31, 2012, of approximately 12 years.

(8)Emission allowances do not have a contractual term or expiration date. If the EPA’s Cross State Air Pollution Rule, which was stayed in December 2011, is reinstated, it will affect our ability to use certain existing emission allowances in the future. See Note 11, “Commitments and Contingencies,” for more information.

Intangible asset amortization expense for the next five fiscal years

	For the year ending December 31
(Millions)	2012		2013		2014		2015		2016
Amortization recorded in nonregulated cost of sales	$	5.9	$	1.8	$	1.4	$	1.3	$	1.1
Amortization recorded in depreciation and amortization expense	2.5		2.0		1.7		1.7		1.5

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FAIR VALUE (Tables)

3 Months Ended

Mar. 31, 2012

FAIR VALUE

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

	March 31, 2012
(Millions)	Level 1		Level 2		Level 3		Total
Risk Management Assets
Utility Segments
Natural gas contracts	$	—	$	5.5	$	—	$	5.5
Financial transmission rights (FTRs)	—		—		1.0		1.0
Petroleum product contracts	0.4		—		—		0.4
Nonregulated Segments
Natural gas contracts	41.5		90.9		11.1		143.5
Electric contracts	61.3		96.8		14.1		172.2
Foreign exchange contracts	—		0.2		—		0.2
Total Risk Management Assets	$	103.2	$	193.4	$	26.2	$	322.8
Risk Management Liabilities
Utility Segments
Natural gas contracts	$	1.6	$	52.9	$	—	$	54.5
FTRs	—		—		0.1		0.1
Coal contract	—		—		13.4		13.4
Nonregulated Segments
Natural gas contracts	47.7		93.2		0.2		141.1
Electric contracts	81.2		183.4		36.0		300.6
Foreign exchange contracts	0.2		—		—		0.2
Total Risk Management Liabilities	$	130.7	$	329.5	$	49.7	$	509.9

	December 31, 2011
(Millions)	Level 1		Level 2		Level 3		Total
Risk Management Assets
Utility Segments
Natural gas contracts	$	0.1	$	9.1	$	—	$	9.2
FTRs	—		—		2.3		2.3
Petroleum product contracts	0.1		—		—		0.1
Nonregulated Segments
Natural gas contracts	50.7		104.1		8.7		163.5
Electric contracts	41.2		71.2		3.9		116.3
Foreign exchange contracts	—		0.2		—		0.2
Total Risk Management Assets	$	92.1	$	184.6	$	14.9	$	291.6
Risk Management Liabilities
Utility Segments
Natural gas contracts	$	5.5	$	39.2	$	—	$	44.7
FTRs	—		—		0.1		0.1
Coal contract	—		—		6.9		6.9
Nonregulated Segments
Natural gas contracts	55.0		105.6		0.4		161.0
Electric contracts	54.2		131.1		15.4		200.7
Foreign exchange contracts	0.2		—		—		0.2
Total Risk Management Liabilities	$	114.9	$	275.9	$	22.8	$	413.6

Schedule of transfers between the levels of the fair value hierarchy

Nonregulated Segments — Electric Contracts

	Three Months Ended March 31, 2012								Three Months Ended March 31, 2011
(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			(0.1		)	$	—	N/A			(2.4		)
Transfers into Level 3 from	—		(5.0		)	N/A			—		(5.4		)	N/A

Nonregulated Segments — Natural Gas Contracts

	Three Months Ended March 31, 2012						Three Months Ended March 31, 2011
(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		1.3		$	—	N/A			0.4
Transfers into Level 3 from	—		2.4		N/A		—		(0.1		)	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 ($/megawatt-month) (1)	170.36
Coal contract	—		13.4		Market-based	Forward market prices ($/ton) (2)	14.6 –15.1
Nonregulated Segments
Natural gas contracts	11.1		0.2		Market-based	Forward market prices ($/dekatherm) (3)	(0.04) –1.54
						Probability of default	11.62% - 50.99%
Electric contracts	14.1		36.0		Market-based	Forward market prices ($/megawatt-hours) (3)	(6.05) - 9.79
						Option volatilities (4)	19.99% - 59.51%
						Monthly curve shaping (5)	(15.03)% - (11.57)%

(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 contract.
(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.
(5)	Represents adjustments made to forward market price curves to disaggregate average prices of multiple periods into discrete monthly prices.

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

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 (losses) gains 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	)

Three Months Ended March 31, 2011	Nonregulated Segments						Utility Segments
(Millions)	Natural Gas			Electric			FTRs			Coal Contract			Total
Balance at the beginning of the period	$	30.2		$	(14.9	)	$	2.9		$	2.5		$	20.7
Net realized and unrealized gains (losses) included in earnings	4.0			(2.9		)	0.1			—			1.2
Net unrealized losses recorded as regulatory assets or liabilities	—			—			(1.1		)	(7.0		)	(8.1		)
Net unrealized losses included in other comprehensive loss	—			(0.7		)	—			—			(0.7		)
Purchases	—			0.3			—			—			0.3
Sales	—			—			(0.1		)	—			(0.1		)
Settlements	(15.2		)	2.5			(0.8		)	(0.4		)	(13.9		)
Net transfers into Level 3	(0.1		)	(5.4		)	—			—			(5.5		)
Net transfers out of Level 3	(0.4		)	2.4			—			—			2.0
Balance at the end of the period	$	18.5		$	(18.7	)	$	1.0		$	(4.9	)	$	(4.1	)
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	$	4.0		$	(2.9	)	$	—		$	—		$	1.1

Schedule of carrying value and estimated fair value of financial instruments

	March 31, 2012				December 31, 2011
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	2,122.1	$	2,272.2	$	2,122.0	$	2,281.5
Preferred stock	51.1		50.9		51.1		51.8

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SHORT-TERM DEBT AND LINES OF CREDIT (Details 2) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Short-term borrowings
Total short-term credit capacity	$ 1,710.0	$ 1,710.0
Letters of credit issued inside credit facilities	33.9	33.7
Short-term borrowings outstanding	305.5	303.3
Available capacity under existing agreements	1,370.6	1,373.0
Revolving credit facility maturing on April 23, 2013 | INTEGRYS ENERGY GROUP, INC.
Short-term borrowings
Total short-term credit capacity	735.0	735.0
Revolving credit facility maturing on April 23, 2013 | WPS
Short-term borrowings
Total short-term credit capacity	115.0	115.0
Revolving credit facility maturing on April 23, 2013 | PGL
Short-term borrowings
Total short-term credit capacity	250.0	250.0
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 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
Commercial paper
Short-term borrowings
Short-term borrowings outstanding	$ 305.5	$ 303.3

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FAIR VALUE (Details 4) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation Calculation
Balance at the beginning of the period	$ (7.9)	$ 20.7
Net realized and unrealized gains (losses) included in earnings	(3.1)	1.2
Net unrealized (losses) gains recorded as regulatory assets or liabilities	(5.7)	(8.1)
Net unrealized gains (losses) included in other comprehensive loss		(0.7)
Purchases	1.1	0.3
Sales	(0.1)	(0.1)
Settlements	(4.0)	(13.9)
Net transfers into Level 3	(2.6)	(5.5)
Net transfers out of Level 3	(1.2)	2.0
Balance at the end of the period	(23.5)	(4.1)
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	(3.6)	1.1
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	8.3	30.2
Net realized and unrealized gains (losses) included in earnings	4.1	4.0
Settlements	(2.6)	(15.2)
Net transfers into Level 3	2.4	(0.1)
Net transfers out of Level 3	(1.3)	(0.4)
Balance at the end of the period	10.9	18.5
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	4.1	4.0
Nonregulated Segments | Electric contracts
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation Calculation
Balance at the beginning of the period	(11.5)	(14.9)
Net realized and unrealized gains (losses) included in earnings	(7.7)	(2.9)
Net unrealized gains (losses) included in other comprehensive loss		(0.7)
Purchases	1.1	0.3
Settlements	1.1	2.5
Net transfers into Level 3	(5.0)	(5.4)
Net transfers out of Level 3	0.1	2.4
Balance at the end of the period	(21.9)	(18.7)
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	(7.7)	(2.9)
Utility Segments | FTRs
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation Calculation
Balance at the beginning of the period	2.2	2.9
Net realized and unrealized gains (losses) included in earnings	0.5	0.1
Net unrealized (losses) gains recorded as regulatory assets or liabilities	0.1	(1.1)
Sales	(0.1)	(0.1)
Settlements	(1.8)	(0.8)
Balance at the end of the period	0.9	1.0
Utility Segments | Coal contract
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation Calculation
Balance at the beginning of the period	(6.9)	2.5
Net unrealized (losses) gains recorded as regulatory assets or liabilities	(5.8)	(7.0)
Settlements	(0.7)	(0.4)
Balance at the end of the period	$ (13.4)	$ (4.9)

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Utility revenues	$ 971.0	$ 1,168.7
Nonregulated revenues	280.3	458.4
Total revenues	1,251.3	1,627.1
Utility cost of fuel, natural gas, and purchased power	472.3	660.7
Nonregulated cost of sales	275.3	404.0
Operating and maintenance expense	261.0	264.6
Depreciation and amortization expense	62.7	62.3
Taxes other than income taxes	28.4	26.8
Operating income	151.6	208.7
Earnings in equity method investments	21.1	19.4
Miscellaneous income	2.4	1.8
Interest expense	(30.5)	(34.8)
Other expense	(7.0)	(13.6)
Income before taxes	144.6	195.1
Provision for income taxes	46.8	71.7
Net income from continuing operations	97.8	123.4
Discontinued operations, net of tax	1.9	0.1
Net income	99.7	123.5
Preferred stock dividends of subsidiary	(0.8)	(0.8)
Net income attributed to common shareholders	$ 98.9	$ 122.7
Average shares of common stock
Basic (in shares)	78.6	78.3
Diluted (in shares)	79.2	78.6
Earnings per common share (basic)
Net income from continuing operations (in dollars per share)	$ 1.23	$ 1.57
Discontinued operations, net of tax (in dollars per share)	$ 0.03
Earnings per common share (basic) (in dollars per share)	$ 1.26	$ 1.57
Earnings per common share (diluted)
Net income from continuing operations (in dollars per share)	$ 1.22	$ 1.56
Discontinued operations, net of tax (in dollars per share)	$ 0.03
Earnings per common share (diluted) (in dollars per share)	$ 1.25	$ 1.56
Dividends per common share declared (in dollars per share)	$ 0.68	$ 0.68

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RISK MANAGEMENT ACTIVITIES (Details 3) (Utility Segments, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 Natural gas contracts Balance Sheet - Regulatory assets (current)	Mar. 31, 2011 Natural gas contracts Balance Sheet - Regulatory assets (current)	Mar. 31, 2012 Natural gas contracts Balance Sheet - Regulatory assets (long-term)	Mar. 31, 2011 Natural gas contracts Balance Sheet - Regulatory assets (long-term)	Mar. 31, 2012 Natural gas contracts Balance Sheet - Regulatory liabilities (current)	Mar. 31, 2011 Natural gas contracts Balance Sheet - Regulatory liabilities (current)	Mar. 31, 2012 Natural gas contracts Balance Sheet - Regulatory liabilities (long-term)	Mar. 31, 2011 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, 2011 Natural gas contracts Income Statement - Utility cost of fuel, natural gas and purchased power	Mar. 31, 2012 FTRs Balance Sheet - Regulatory assets (current)	Mar. 31, 2011 FTRs Balance Sheet - Regulatory assets (current)	Mar. 31, 2012 FTRs Balance Sheet - Regulatory liabilities (current)	Mar. 31, 2011 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, 2011 Petroleum product contracts Balance Sheet - Regulatory liabilities (current)	Mar. 31, 2012 Petroleum product contracts Income Statement - Operating and maintenance expense	Mar. 31, 2011 Petroleum product contracts Income Statement - Operating and maintenance expense	Mar. 31, 2012 Coal contract Balance Sheet - Regulatory assets (current)	Mar. 31, 2011 Coal contract Balance Sheet - Regulatory assets (current)	Mar. 31, 2012 Coal contract Balance Sheet - Regulatory assets (long-term)	Mar. 31, 2011 Coal contract Balance Sheet - Regulatory assets (long-term)	Mar. 31, 2011 Coal contract Balance Sheet - Regulatory liabilities (long-term)	Mar. 31, 2012 Purchases Natural gas contracts therm	Dec. 31, 2011 Purchases Natural gas contracts therm	Mar. 31, 2012 Purchases Petroleum product contracts bbl	Dec. 31, 2011 Purchases Petroleum product contracts bbl	Mar. 31, 2012 Purchases Coal contract ton	Dec. 31, 2011 Purchases Coal contract ton	Mar. 31, 2012 Sales Natural gas contracts Cash flow hedges therm	Mar. 31, 2012 Other transactions FTRs kWh	Dec. 31, 2011 Other transactions FTRs kWh
Risk management activities
Notional volume of outstanding non-hedge derivative contracts																									755,500,000.0	1,122,700,000.0	51,872.0	46,872.0	3,900,000.0	4,100,000.0	300,000.0	1,911,000,000.0	5,077,500,000.0
Unrealized gains (losses) recorded related to non-hedge derivatives	$ (6.4)	$ 11.2	$ (0.8)	$ 1.6	$ (3.7)	$ (0.1)	$ 0.1	$ 0.1	$ 0.1	$ 0.1	$ 0.4	$ 0.1	$ (0.3)	$ (1.2)	$ 0.1	$ 0.1	$ 0.4	$ 0.1	$ 0.5	$ (3.1)	$ (0.5)	$ (3.5)	$ (3.2)	$ (3.7)

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
CONDENSED CONSOLIDATED BALANCE SHEETS
Accounts receivable and accrued unbilled revenues, reserves (in dollars)	$ 43.4	$ 47.1
Property, plant, and equipment, accumulated depreciation (in dollars)	$ 3,057.7	$ 3,018.7
Common stock, par value (in dollars per share)	$ 1
Common stock, shares authorized	200,000,000
Common stock, shares issued	78,287,906	78,287,906
Common stock, shares outstanding	77,916,543	77,904,935
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

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EMPLOYEE BENEFIT PLANS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Pension Benefits
Components of net periodic benefit cost
Service cost	$ 12.4	$ 11.3
Interest cost	19.8	20.5
Expected return on plan assets	(27.1)	(24.7)
Amortization of prior service cost (credit)	1.2	1.3
Amortization of net actuarial loss	8.3	4.7
Net periodic benefit cost	14.6	13.1
Contributed to benefit plans	171.5
Additional contributions to plans during the remainder of fiscal year	3.8
Other Benefits
Components of net periodic benefit cost
Service cost	5.5	5.0
Interest cost	7.2	7.7
Expected return on plan assets	(7.0)	(5.0)
Amortization of transition obligation	0.1	0.1
Amortization of prior service cost (credit)	(0.9)	(0.9)
Amortization of net actuarial loss	1.6	1.1
Net periodic benefit cost	6.5	8.0
Contributed to benefit plans	75.1
Additional contributions to plans during the remainder of fiscal year	$ 39.1

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INCOME TAXES (Tables)

3 Months Ended

Mar. 31, 2012

INCOME TAXES

Schedule of effective tax rates

	Three Months Ended March 31
	2012		2011
Effective Tax Rate	32.4	%	36.8	%

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COMMON EQUITY (Details 3) (USD $) In Millions, unless otherwise specified			3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2012 Cash Flow Hedges.	Mar. 31, 2012 Defined Benefit Pension Plans	Mar. 31, 2012 Accumulated Other Comprehensive Income (Loss)
Changes to accumulated other comprehensive loss
Accumulated other comprehensive loss, balance at beginning of period	$ (41.0)	$ (42.5)	$ (11.5)	$ (31.0)	$ (42.5)
Current period other comprehensive income			1.2	0.3	1.5
Accumulated other comprehensive loss, balance at end of period	$ (41.0)	$ (42.5)	$ (10.3)	$ (30.7)	$ (41.0)

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COMMON EQUITY

3 Months Ended

Mar. 31, 2012

COMMON EQUITY

COMMON EQUITY

NOTE 15—COMMON EQUITY

We had no changes to issued common stock during the three months ended March 31, 2012.

Beginning May 1, 2011, shares were purchased on the open market to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans.

The following table reconciles common shares issued and outstanding:

	March 31, 2012				December 31, 2011
	Shares	Average Cost			Shares	Average Cost
Common stock issued	78,287,906				78,287,906
Less:
Deferred compensation rabbi trust	371,363	$	45.71	*	382,971	$	44.54	*
Total common shares outstanding	77,916,543				77,904,935

*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 calculation of diluted earnings per share for the three months ended March 31, 2012, and 2011, each excluded 0.8 million 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)	2012			2011
Numerator:
Net income from continuing operations	$	97.8		$	123.4
Discontinued operations, net of tax	1.9			0.1
Preferred stock dividends of subsidiary	(0.8		)	(0.8		)
Net income attributed to common shareholders	$	98.9		$	122.7
Denominator:
Average shares of common stock — basic	78.6			78.3
Effect of dilutive securities
Stock-based compensation	0.4			0.3
Deferred compensation	0.2			—
Average shares of common stock — diluted	79.2			78.6
Earnings per common share
Basic	$	1.26		$	1.57
Diluted	1.25			1.56

Accumulated Other Comprehensive Loss

The following table shows the changes to our accumulated other comprehensive loss from December 31, 2011 to March 31, 2012:

	Cash Flow Hedges			Defined Benefit Pension Plans			Accumulated Other Comprehensive Income (Loss)
Beginning balance at December 31, 2011	$	(11.5	)	$	(31.0	)	$	(42.5	)
Current period other comprehensive income	1.2			0.3			1.5
Ending balance at March 31, 2012	$	(10.3	)	$	(30.7	)	$	(41.0	)

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 normal dividends on its common stock of no more than 103% of the previous year’s common stock dividend. In addition, the PSCW currently requires WPS to maintain a calendar year average financial common equity ratio of 50.24% or higher. WPS must obtain PSCW approval if the payment of dividends would cause it to fall below this authorized level of common equity. 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, 2012, these covenants did not restrict the payment of any dividends beyond the amount restricted under our subsidiary requirements described above.

As of March 31, 2012, total restricted net assets were approximately $1,410.5 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was approximately $112.5 million at March 31, 2012.

We also 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, 2012, capital transactions with subsidiaries were as follows (in millions):

Subsidiary	Dividends To Parent		Return Of Capital To Parent		Equity Contributions From Parent
WPS	$	26.4	$	—	$	40.0
WPS Investments, LLC *	16.7		—		3.4
MERC	—		15.0		—
IBS	—		3.0		—
MGU	—		6.0		—
UPPCO	—		2.5		8.5
Total	$	43.1	$	26.5	$	51.9

*WPS Investments, LLC is a consolidated subsidiary that is jointly owned by us, WPS, and UPPCO. At March 31, 2012, WPS and UPPCO had a 12.17% and 2.59% ownership interest, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2012, all equity contributions to WPS Investments, LLC were made solely by us.

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GUARANTEES (Tables)

3 Months Ended

Mar. 31, 2012

GUARANTEES

Schedule of outstanding guarantees

	Total Amounts		Expiration
(Millions)	Committed at March 31, 2012		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees supporting commodity transactions of subsidiaries (1)	$	623.9	$	407.7	$	6.9	$	209.3
Standby letters of credit (2)	66.9		35.3		31.5		0.1
Surety bonds (3)	13.8		13.8		—		—
Other guarantees (4)	42.6		20.0		—		22.6
Total guarantees	$	747.2	$	476.8	$	38.4	$	232.0

(1)Consists of parental guarantees of $456.2 million to support the business operations of Integrys Energy Services; $111.8 million and $48.9 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 $64.1 million issued to support Integrys Energy Services’ operations and $2.8 million issued to support UPPCO, WPS, MGU, NSG, MERC, PGL, and Pinnacle CNG Systems. 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) $20.0 million related to the sale agreement for Integrys Energy Services’ United States wholesale electric marketing and trading business, which included a number of customary representations, warranties, and indemnification provisions. In addition, for a two-year period, counterparty payment default risk was retained with approximately 50% of the counterparties associated with the commodity contracts transferred in this transaction. An insignificant liability was recorded related to the fair value of this counterparty payment default risk; (b) $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; (c) $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 the balance sheets); and (d) $7.6 million related to other indemnifications primarily for workers compensation coverage. This amount is not reflected on our balance sheets.

Schedule of parental guarantees

(Millions)	March 31, 2012
Guarantees supporting commodity transactions	$	456.2
Standby letters of credit	64.1
Surety bonds	3.2
Other	35.5
Total guarantees	$	559.0

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FAIR VALUE

3 Months Ended

Mar. 31, 2012

FAIR VALUE

FAIR VALUE

NOTE 17—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, 2012
(Millions)	Level 1		Level 2		Level 3		Total
Risk Management Assets
Utility Segments
Natural gas contracts	$	—	$	5.5	$	—	$	5.5
Financial transmission rights (FTRs)	—		—		1.0		1.0
Petroleum product contracts	0.4		—		—		0.4
Nonregulated Segments
Natural gas contracts	41.5		90.9		11.1		143.5
Electric contracts	61.3		96.8		14.1		172.2
Foreign exchange contracts	—		0.2		—		0.2
Total Risk Management Assets	$	103.2	$	193.4	$	26.2	$	322.8
Risk Management Liabilities
Utility Segments
Natural gas contracts	$	1.6	$	52.9	$	—	$	54.5
FTRs	—		—		0.1		0.1
Coal contract	—		—		13.4		13.4
Nonregulated Segments
Natural gas contracts	47.7		93.2		0.2		141.1
Electric contracts	81.2		183.4		36.0		300.6
Foreign exchange contracts	0.2		—		—		0.2
Total Risk Management Liabilities	$	130.7	$	329.5	$	49.7	$	509.9

	December 31, 2011
(Millions)	Level 1		Level 2		Level 3		Total
Risk Management Assets
Utility Segments
Natural gas contracts	$	0.1	$	9.1	$	—	$	9.2
FTRs	—		—		2.3		2.3
Petroleum product contracts	0.1		—		—		0.1
Nonregulated Segments
Natural gas contracts	50.7		104.1		8.7		163.5
Electric contracts	41.2		71.2		3.9		116.3
Foreign exchange contracts	—		0.2		—		0.2
Total Risk Management Assets	$	92.1	$	184.6	$	14.9	$	291.6
Risk Management Liabilities
Utility Segments
Natural gas contracts	$	5.5	$	39.2	$	—	$	44.7
FTRs	—		—		0.1		0.1
Coal contract	—		—		6.9		6.9
Nonregulated Segments
Natural gas contracts	55.0		105.6		0.4		161.0
Electric contracts	54.2		131.1		15.4		200.7
Foreign exchange contracts	0.2		—		—		0.2
Total Risk Management Liabilities	$	114.9	$	275.9	$	22.8	$	413.6

The risk management assets and liabilities listed in the tables 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 — Electric Contracts

	Three Months Ended March 31, 2012								Three Months Ended March 31, 2011
(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			(0.1		)	$	—	N/A			(2.4		)
Transfers into Level 3 from	—		(5.0		)	N/A			—		(5.4		)	N/A

Nonregulated Segments — Natural Gas Contracts

	Three Months Ended March 31, 2012						Three Months Ended March 31, 2011
(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		1.3		$	—	N/A			0.4
Transfers into Level 3 from	—		2.4		N/A		—		(0.1		)	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. We recognize transfers between the levels of the fair value hierarchy at the value as of the end of the reporting period.

We determine fair value using a market-based approach that uses observable market inputs where available, and internally developed inputs where observable market data is not readily available. For the unobservable inputs, consideration is given to the assumptions that market participants would use in valuing the asset or liability. These factors include not only the credit standing of the counterparties involved, but also the impact of our nonperformance risk on our liabilities.

When possible, we base the valuations of our risk management assets and liabilities on quoted prices for identical assets in active markets. These valuations are classified in Level 1. The valuations of certain contracts include inputs related to market price risk (commodity or interest rate), price volatility (for option contracts), price correlation (for cross commodity contracts), probability of default, and time value. These inputs are available through multiple sources, including brokers and over-the-counter and online exchanges. Transactions valued using these inputs are classified in Level 2.

Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows:

·While forward price curves may have been based on observable information, significant assumptions may have been made regarding monthly shaping and locational basis differentials.

·Certain transactions were valued using price curves that extended beyond an observable period. Assumptions were made to extrapolate prices from the last observable period through the end of the transaction term, primarily through the use of historically settled data or correlations to other locations.

We conduct a thorough review of fair value hierarchy classifications on a quarterly basis.

We have established risk oversight committees whose primary responsibility includes directly or indirectly ensuring that all valuation methods are applied in accordance with predefined policies. The development and maintenance of our forward price curves has been assigned to our risk management department, which is part of the corporate treasury function. This group is separate and distinct from any of the trading functions within the organization. To validate the reasonableness of our fair value inputs, our risk management department compares changes in valuation and researches any significant differences in order to determine the underlying cause. Corrections to the fair value inputs are made if necessary.

The significant unobservable inputs used in the valuation that resulted in categorization within Level 3 were as follows at March 31, 2012. 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 ($/megawatt-month) (1)	170.36
Coal contract	—		13.4		Market-based	Forward market prices ($/ton) (2)	14.6 –15.1
Nonregulated Segments
Natural gas contracts	11.1		0.2		Market-based	Forward market prices ($/dekatherm) (3)	(0.04) –1.54
						Probability of default	11.62% - 50.99%
Electric contracts	14.1		36.0		Market-based	Forward market prices ($/megawatt-hours) (3)	(6.05) - 9.79
						Option volatilities (4)	19.99% - 59.51%
						Monthly curve shaping (5)	(15.03)% - (11.57)%

(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 contract.
(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.
(5)	Represents adjustments made to forward market price curves to disaggregate average prices of multiple periods into discrete monthly prices.

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, 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 (losses) gains 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	)

Three Months Ended March 31, 2011	Nonregulated Segments						Utility Segments
(Millions)	Natural Gas			Electric			FTRs			Coal Contract			Total
Balance at the beginning of the period	$	30.2		$	(14.9	)	$	2.9		$	2.5		$	20.7
Net realized and unrealized gains (losses) included in earnings	4.0			(2.9		)	0.1			—			1.2
Net unrealized losses recorded as regulatory assets or liabilities	—			—			(1.1		)	(7.0		)	(8.1		)
Net unrealized losses included in other comprehensive loss	—			(0.7		)	—			—			(0.7		)
Purchases	—			0.3			—			—			0.3
Sales	—			—			(0.1		)	—			(0.1		)
Settlements	(15.2		)	2.5			(0.8		)	(0.4		)	(13.9		)
Net transfers into Level 3	(0.1		)	(5.4		)	—			—			(5.5		)
Net transfers out of Level 3	(0.4		)	2.4			—			—			2.0
Balance at the end of the period	$	18.5		$	(18.7	)	$	1.0		$	(4.9	)	$	(4.1	)
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	$	4.0		$	(2.9	)	$	—		$	—		$	1.1

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, 2012				December 31, 2011
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	2,122.1	$	2,272.2	$	2,122.0	$	2,281.5
Preferred stock	51.1		50.9		51.1		51.8

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, without considering the effect of third-party credit enhancements. 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

VARIABLE INTEREST ENTITIES (Details)	3 Months Ended		12 Months Ended
	Mar. 31, 2012 agreement entity MW	Dec. 31, 2011 MW	Dec. 31, 2011 PTI CNG Fuels LLC
VARIABLE INTEREST ENTITIES
Number of variable interest entities	2
Number of purchased power agreements that reimburse an independent power producing entity	1
Capacity available from variable interest entities under power purchase agreements (in megawatts)	517.5	517.5
Variable Interest Entity
Variable interest entity ownership interest acquired (as a percent)			50.00%

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Operating Activities
Net income	$ 99.7	$ 123.5
Adjustments to reconcile net income to net cash provided by operating activities
Discontinued operations, net of tax	(1.9)	(0.1)
Depreciation and amortization expense	62.7	62.3
Recoveries and refunds of regulatory assets and liabilities	9.5	13.5
Net unrealized losses on nonregulated energy contracts	44.7	0.7
Bad debt expense	10.1	11.5
Pension and other postretirement expense	17.6	21.1
Pension and other postretirement contributions	(246.6)	(106.4)
Deferred income taxes and investment tax credits	30.0	67.2
Gain on sale of assets	(0.2)	(0.1)
Equity income, net of dividends	(3.8)	(3.0)
Other	2.6	10.2
Changes in working capital
Collateral on deposit	(13.7)	(5.2)
Accounts receivable and accrued unbilled revenues	49.9	(50.1)
Inventories	132.7	152.7
Other current assets	54.5	28.3
Accounts payable	(77.4)	(23.8)
Temporary LIFO liquidation credit	36.7	119.2
Other current liabilities	18.7	(26.0)
Net cash provided by operating activities	225.8	395.5
Investing Activities
Capital expenditures	(123.0)	(51.2)
Proceeds from the sale or disposal of assets	1.4	1.1
Capital contributions to equity method investments	(10.4)	(6.2)
Other	(4.7)	0.1
Net cash used for investing activities	(136.7)	(56.2)
Financing Activities
Short-term debt, net	2.2	57.9
Repayment of long-term debt		(325.0)
Payment of dividends
Preferred stock of subsidiary	(0.8)	(0.8)
Common stock	(53.0)	(47.4)
Issuance of common stock		7.2
Payments made on derivative contracts related to divestitures classified as financing activities	(9.0)	(11.1)
Other	(14.3)	(3.8)
Net cash used for financing activities	(74.9)	(323.0)
Net change in cash and cash equivalents	14.2	16.3
Cash and cash equivalents at beginning of period	28.1	179.0
Cash and cash equivalents at end of period	$ 42.3	$ 195.3

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Net income	$ 99.7	$ 123.5
Cash flow hedges
Unrealized net losses arising during period, net of tax of $(0.2) million and $(2.4) million, respectively	(0.3)	(4.1)
Reclassification of net losses to net income, net of tax of $1.0 million and $5.1 million, respectively	1.5	8.4
Cash flow hedges, net	1.2	4.3
Defined benefit pension plans
Amortization of pension and other postretirement costs included in net periodic benefit cost, net of tax of $0.3 million and $0.2 million, respectively	0.3	0.2
Other comprehensive income, net of tax	1.5	4.5
Comprehensive income	101.2	128.0
Less: preferred stock dividends of subsidiary	(0.8)	(0.8)
Comprehensive income attributed to common shareholders	$ 100.4	$ 127.2

XML

INCOME TAXES

3 Months Ended

Mar. 31, 2012

INCOME TAXES

INCOME TAXES

NOTE 10—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
	2012		2011
Effective Tax Rate	32.4	%	36.8	%

Our effective tax rate for the three months ended March 31, 2012, was lower than the federal statutory tax rate of 35%. This difference primarily related to the federal income tax benefit of tax credits related to wind production and a remeasurement of an unrecognized tax benefit liability that better reflects how the underlying uncertain tax positions are resolving themselves in various taxing jurisdictions. Other state income tax obligations partially offset the lower effective tax rate.

Our effective tax rate for the three months ended March 31, 2011, was higher than the federal statutory tax rate of 35%. This difference primarily related to state income tax obligations, partially offset by tax credits related to wind production, along with other tax credits.

During the three months ended March 31, 2012, we remeasured and decreased our liability for unrecognized tax benefits by $2.7 million that  better reflects how the underlying uncertain tax positions are resolving themselves in various taxing jurisdictions. We reduced the provision for income taxes related to this remeasurement, of which a portion was reported as discontinued operations.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2012	Apr. 26, 2012
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, 2012
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		78,287,906
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1

XML

COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2012

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

NOTE 11—COMMITMENTS AND CONTINGENCIES

Commodity 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 purchase obligations described below were as of March 31, 2012.

· The electric utility segment had obligations of $186.3 million related to coal supply and transportation that extend through 2016, obligations of $1,213.9 million for either capacity or energy related to purchased power that extend through 2029, and obligations of $5.4 million for other commodities that extend through 2013.

· The natural gas utility segment had obligations of $836.7 million related to natural gas supply and transportation contracts that extend through 2028.

· Integrys Energy Services had obligations of $218.9 million, primarily related to electricity and natural gas supply contracts that extend through 2021.

· We and our subsidiaries also had commitments of $536.1 million in the form of purchase orders issued to various vendors that relate to normal business operations, including construction projects.

Environmental

Clean Air Act (CAA) New Source Review Issues

Weston and Pulliam Plants:

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 continues to meet with the EPA and exchange proposals on a possible resolution. We are currently unable to estimate the possible loss or range of loss related to this matter.

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. WPS is working on a possible resolution with the Sierra Club and the EPA. We are currently unable to estimate the possible loss or range of loss related to this matter.

Columbia and Edgewater Plants:

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 WPS). The NOV alleges violations of the CAA’s New Source Review requirements related to certain projects completed at those plants. WP&L and the other joint owners exchanged proposals with the EPA on a possible resolution. We are currently unable to estimate the possible loss or range of loss related to this matter.

In September 2010, the Sierra Club filed a lawsuit against WP&L, which included allegations that modifications made at the Columbia plant did not comply with the CAA. While the previous stay has been lifted and the case is moving forward to a December 2012 trial, the Sierra Club continues to participate in settlement negotiations with the EPA and the joint owners of the Columbia plant to seek resolution. We are currently unable to estimate the possible loss or range of loss related to this matter.

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. The previous stay of this case has been extended until July 15, 2012, and settlement negotiations with the Sierra Club, the EPA, and the joint owners of the Edgewater plant continue. We are currently unable to estimate the possible loss or range of loss related to this matter.

EPA Settlements with Other Utilities:

In response to the EPA’s CAA enforcement initiative, several utilities elected to settle with the EPA, while others are in litigation. The fines, penalties, and costs of supplemental beneficial environmental projects associated with settlements involving comparably-sized facilities to Weston and Pulliam combined ranged between $6 million and $30 million. The regulatory interpretations upon which the lawsuits or settlements are based may change depending on future court decisions made in the pending litigation.

If it were settled or determined that historical projects at the Weston, Pulliam, Columbia, and Edgewater plants required either a state or federal CAA permit, WPS may, under the applicable statutes, be required to complete the following remedial steps:

· shut down the facility,

· install additional pollution control equipment and/or impose emission limitations, and/or

· conduct a supplemental beneficial environmental project.

In addition, WPS may also be required to pay a fine. Finally, under the CAA, citizen groups may pursue a claim.

Weston Air Permits

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, the WDNR, WPS, 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 and the Sierra Club to resolve this issue. We do not expect this matter to have a material impact on our financial statements.

Weston Title V Air Permit:

In November 2010, the WDNR provided a draft revised permit. WPS objected to proposed changes in mercury limits and requirements on the boilers as beyond the authority of the WDNR. WPS and the WDNR continue to meet to resolve these issues. In September 2011, the WDNR issued a draft revised permit and a request for public comments. WPS filed comments objecting to certain provisions in the draft permit. We do not expect this matter to have a material impact on our financial statements.

WDNR Issued NOVs:

Since 2008, WPS received four NOVs from the WDNR alleging various violations of the different air permits for the entire Weston plant, Weston 4, Weston 1, and Weston 2, as well as one 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 dismissed two of the NOVs and referred the other three NOVs to the state Justice Department for enforcement. We do not expect this matter to have a material impact on our financial statements.

Pulliam Title V Air Permit

The WDNR issued the 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 objecting to this permit.

WPS also challenged the permit in a contested case proceeding and Petition for Judicial Review. The Petition was dismissed in an order remanding the matter to the WDNR. In February 2011, the WDNR granted a contested case proceeding before an Administrative Law Judge on the issues raised by WPS, which included averaging times in the emission limits in the permit. WPS participated in the contested case proceeding in October 2011. In December 2011, the Administrative Law Judge did not require the WDNR to insert averaging times, for which WPS had argued. WPS has decided not to appeal.

In October 2010, WPS received from the Sierra Club a copy of an NOI to file a civil lawsuit against the EPA based on what the Sierra Club alleges to be the EPA’s unreasonable delay in performing its duties related to the grant or denial of the permit. WPS received notification that the Sierra Club filed suit against the EPA in April 2011. WPS intervened in the case as a necessary party to protect its interests. The WDNR sent the proposed permit to the EPA for a 45-day review, which allowed the parties to enter into a settlement agreement that has not yet been entered by the court.

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 October 2009, the EPA issued an order objecting to the permit renewal issued by the WDNR for the Columbia plant. The order determined that the WDNR did not adequately analyze whether a project in 2006 constituted a “major modification that required a permit.”  The EPA’s order directed the WDNR to resolve the objections within 90 days and “terminate, modify, or revoke and reissue” the permit accordingly.

In July 2010, WPS, along with its co-owners, received from the Sierra Club a copy of an NOI to file a civil lawsuit against the EPA. The Sierra Club alleges that the EPA should assert jurisdiction over the permit because the WDNR failed to respond to the EPA’s objection within 90 days.

In September 2010, the WDNR issued a draft construction permit and a draft revised Title V permit in response to the EPA’s order. In November 2010, the EPA notified the WDNR that the EPA “does not believe the WDNR’s proposal is responsive to the order.”  In January 2011, the WDNR issued a letter stating that upon review of the submitted public comments, the WDNR has determined not to issue the draft permits that were proposed to respond to the EPA’s order. In February 2011, the Sierra Club filed for a declaratory action, claiming that the EPA had to assert jurisdiction over the permits. In May 2011, the WDNR issued a second draft Title V permit in response to the EPA’s order. WPS is monitoring this situation with WP&L and meeting with the WDNR. 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, Chapter NR 446, requires a 40% reduction from the 2002 through 2004 baseline mercury emissions in Phase I, beginning January 1, 2010, through the end of 2014. In Phase II, which begins in 2015, electric generating units above 150 megawatts will be required to reduce mercury emissions by 90%. 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, 2012, WPS estimates capital costs of approximately $2 million, which includes estimates for both wholly owned and jointly owned plants, to achieve the required Phase I and Phase II reductions. The capital costs are expected to be recovered in future rate cases.

In December 2011, the EPA issued the final Utility Mercury and Air Toxics rule that will regulate emissions of mercury and other hazardous air pollutants. 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:

The EPA issued the Clean Air Interstate Rule (CAIR) in 2005 in order to reduce sulfur dioxide and nitrogen oxide emissions from utility boilers located in 29 states, including Wisconsin, Michigan, Pennsylvania, and New York. In July 2008, the United States Court of Appeals (Court of Appeals) issued a decision vacating CAIR, which the EPA appealed. In December 2008, the Court of Appeals reinstated CAIR and directed the EPA to address the deficiencies noted in its previous ruling to vacate CAIR. In July 2011, the EPA issued a final CAIR replacement rule known as the Cross State Air Pollution Rule (CSAPR). The new rule was to become effective January 1, 2012; however, on December 30, 2011, the D.C. Circuit Court (Court) issued a decision that stayed the rule pending the Court’s resolution of the petitions for review. The Court directed the EPA to implement CAIR during the stay period. In January 2012, a briefing and oral argument schedule was set. Oral arguments were held on April 13, 2012. In comparison to the CAIR rule, CSAPR, in the version that was stayed, significantly reduced the emission allowances allocated to our subsidiaries’ existing units for sulfur dioxide and nitrogen oxide in 2012, with a further reduction in 2014.

CSAPR also established new sulfur dioxide and nitrogen oxide emission allowances and did not allow carryover of the existing nitrogen oxide emission allowances allocated to WPS under CAIR. WPS did not acquire any CAIR nitrogen oxide emission allowances for 2012 and beyond other than those directly allocated to it, which were free. Sulfur dioxide emission allowances allocated under the Acid Rain Program will continue to be issued and surrendered independent of the stayed CSAPR emission allowance program. Thus, we do not expect any material impact on our financial statements as a result of being unable to carry over existing emission allowances.

Under CAIR, units affected by the Best Available Retrofit Technology (BART) rule are considered in compliance with BART for sulfur dioxide and nitrogen oxide emissions if they are in compliance with 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. The EPA has proposed that units in compliance with CSAPR, if the stay is lifted and CSAPR is reinstated, will also be considered in compliance with BART.

The Court may uphold CSAPR, invalidate CSAPR, or direct the EPA to make changes to CSAPR. In order to be in compliance with the stayed version of CSAPR, additional sulfur dioxide and nitrogen oxide controls would need to be installed, emission allowances would need to be purchased, and/or our subsidiaries would have to make other changes to how they operate their existing units. The installation of any necessary controls will be scheduled as part of WPS’s long-term maintenance plan for its existing units; however, WPS does not currently believe it could meet the stayed CSAPR’s sulfur dioxide and nitrogen oxide emission limits without purchasing additional emission allowances or changing how its existing units are operated. Due to the uncertainty surrounding the rule, we are currently unable to predict whether, or if, additional emission allowances would be available to purchase or how much it would cost to comply. We are also currently unable to predict whether CSAPR, or any future version of CSAPR, will cause WPS to idle or abandon certain units or impact the estimated useful lives of certain units. WPS expects to recover any future compliance costs in future rates. The 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, 2012, we estimated and accrued for $608.1 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, 2012, cash expenditures for environmental remediation not yet recovered in rates were $15.6 million. We recorded a regulatory asset of $623.7 million at March 31, 2012, which is net of insurance recoveries received of $59.9 million, related to the expected recovery of both cash expenditures and estimated future expenditures through rates.

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 WPS, MGU, PGL, and NSG. 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 rate recovery of such costs.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Unrealized gain (loss) arising during period, tax	$ (0.2)	$ (2.4)
Reclassification adjustments for (gains) losses realized in net income, tax	1.0	5.1
Amortization of pension and other postretirement costs, tax	$ 0.3	$ 0.2

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INVESTMENT IN ATC

3 Months Ended

Mar. 31, 2012

INVESTMENT IN ATC

INVESTMENT IN ATC

NOTE 5—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, 2012. ATC is a for-profit, transmission-only company regulated by FERC. ATC owns, maintains, monitors, and operates electric transmission assets in portions of Wisconsin, Michigan, Minnesota, and Illinois.

The following table shows changes to our investment in ATC.

	Three Months Ended March 31
(Millions)	2012		2011
Balance at the beginning of period	$	439.4	$	416.3
Add: Equity in net income	20.8		19.2
Add: Capital contributions	3.4		3.4
Less: Dividends received	16.7		16.2
Balance at the end of period	$	446.9	$	422.7

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

	Three Months Ended March 31
(Millions)	2012		2011
Income statement data
Revenues	$	147.7	$	139.6
Operating expenses	69.6		63.1
Other expense	20.0		22.3
Net income *	$	58.1	$	54.2

*As most income taxes are the responsibility of its members, ATC does not report a provision for its members’ income taxes in its income statements.

(Millions)	March 31, 2012		December 31, 2011
Balance sheet data
Current assets	$	57.1	$	58.7
Noncurrent assets	3,099.0		3,053.7
Total assets	$	3,156.1	$	3,112.4
Current liabilities	$	314.5	$	298.5
Long-term debt	1,400.0		1,400.0
Other noncurrent liabilities	88.1		82.6
Members’ equity	1,353.5		1,331.3
Total liabilities and members’ equity	$	3,156.1	$	3,112.4

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DISCONTINUED OPERATIONS

3 Months Ended

Mar. 31, 2012

DISCONTINUED OPERATIONS

DISCONTINUED OPERATIONS

NOTE 4—DISCONTINUED OPERATIONS

Holding Company and Other Segment

During the three-month period ended March 31, 2012, we recorded a $1.9 million after-tax gain in discontinued operations at the holding company and other segment when we remeasured an unrecognized tax benefit liability that better reflects how the underlying uncertain tax positions are resolving themselves in various taxing jurisdictions.

Integrys Energy Services

During the three-month period ended March 31, 2011, Integrys Energy Services recorded a $0.1 million after-tax gain in discontinued operations when contingent payments were earned related to the 2009 sale of its energy management consulting business.

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VARIABLE INTEREST ENTITIES

3 Months Ended

Mar. 31, 2012

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

NOTE 16—VARIABLE INTEREST ENTITIES

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 will be 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, 2012, and December 31, 2011, 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 insignificant.

We have variable interests in two entities through power purchase agreements relating to the cost of fuel. One of these purchased power agreements reimburses an independent power producing entity for coal costs relating to purchased energy. There is no obligation to purchase energy under the agreement. This contract expires in 2014. The other agreement contains a tolling arrangement in which we supply the scheduled fuel and purchase capacity and energy from the facility. This contract expires in 2016. As of March 31, 2012, and December 31, 2011, we had approximately 517.5 megawatts of capacity available under these agreements. We evaluated each of these variable interest entities 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 contracts compared with the remaining lives of the plants and the fact that we do not have the power to direct the operations and maintenance of the facilities, we determined we are not the primary beneficiary of these variable interest entities. At March 31, 2012, and December 31, 2011, the assets and liabilities on the balance sheets that related to our involvement with these variable interest entities 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 these contracts. There is not a significant potential exposure to loss as a result of involvement with the variable interest entities.

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GUARANTEES

3 Months Ended

Mar. 31, 2012

GUARANTEES

GUARANTEES

NOTE 12—GUARANTEES

The following table shows our outstanding guarantees:

	Total Amounts		Expiration
(Millions)	Committed at March 31, 2012		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees supporting commodity transactions of subsidiaries (1)	$	623.9	$	407.7	$	6.9	$	209.3
Standby letters of credit (2)	66.9		35.3		31.5		0.1
Surety bonds (3)	13.8		13.8		—		—
Other guarantees (4)	42.6		20.0		—		22.6
Total guarantees	$	747.2	$	476.8	$	38.4	$	232.0

(1)Consists of parental guarantees of $456.2 million to support the business operations of Integrys Energy Services; $111.8 million and $48.9 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 $64.1 million issued to support Integrys Energy Services’ operations and $2.8 million issued to support UPPCO, WPS, MGU, NSG, MERC, PGL, and Pinnacle CNG Systems. 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) $20.0 million related to the sale agreement for Integrys Energy Services’ United States wholesale electric marketing and trading business, which included a number of customary representations, warranties, and indemnification provisions. In addition, for a two-year period, counterparty payment default risk was retained with approximately 50% of the counterparties associated with the commodity contracts transferred in this transaction. An insignificant liability was recorded related to the fair value of this counterparty payment default risk; (b) $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; (c) $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 the balance sheets); and (d) $7.6 million related to other indemnifications primarily for workers compensation coverage. This amount is not reflected on our balance sheets.

We have provided total parental guarantees of $559.0 million on behalf of Integrys Energy Services as shown in the table below. Our exposure under these guarantees related to existing transactions at March 31, 2012, was approximately $319.3 million.

(Millions)	March 31, 2012
Guarantees supporting commodity transactions	$	456.2
Standby letters of credit	64.1
Surety bonds	3.2
Other	35.5
Total guarantees	$	559.0

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SHORT-TERM DEBT AND LINES OF CREDIT

3 Months Ended

Mar. 31, 2012

SHORT-TERM DEBT AND LINES OF CREDIT

SHORT-TERM DEBT AND LINES OF CREDIT

NOTE 8—SHORT-TERM DEBT AND LINES OF CREDIT

Our short-term borrowings were as follows:

(Millions, except percentages)	March 31, 2012			December 31, 2011
Commercial paper outstanding	$	305.5		$	303.3
Average discount rate on outstanding commercial paper	0.34		%	0.31		%

The commercial paper outstanding at March 31, 2012, had maturity dates ranging from April 2, 2012, through April 30, 2012.

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

(Millions)	2012		2011
Average amount of commercial paper outstanding	$	357.5	$	102.7
Average amount of short-term notes payable outstanding	—		10.0

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:

(Millions)	Maturity	March 31, 2012		December 31, 2011
Revolving credit facility (Integrys Energy Group)	04/23/13	$	735.0	$	735.0
Revolving credit facility (Integrys Energy Group)	05/17/16	200.0		200.0
Revolving credit facility (Integrys Energy Group)	05/17/14	275.0		275.0
Revolving credit facility (WPS)	04/23/13	115.0		115.0
Revolving credit facility (WPS)	05/17/14	135.0		135.0
Revolving credit facility (PGL)	04/23/13	250.0		250.0
Total short-term credit capacity		$	1,710.0	$	1,710.0
Less:
Letters of credit issued inside credit facilities		$	33.9	$	33.7
Commercial paper outstanding		305.5		303.3
Available capacity under existing agreements		$	1,370.6	$	1,373.0

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STOCK-BASED COMPENSATION (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Stock-based compensation expense and the related deferred tax benefit recognized in income
Total stock-based compensation expense	$ 3.3	$ 1.5
Deferred income tax benefit	1.3	0.6
Performance Stock Rights
Stock-based compensation expense and the related deferred tax benefit recognized in income
Total stock-based compensation expense	1.2	(0.7)
Restricted Shares and Restricted Share Units
Stock-based compensation expense and the related deferred tax benefit recognized in income
Total stock-based compensation expense	$ 2.1	$ 2.2

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INVENTORIES

3 Months Ended

Mar. 31, 2012

INVENTORIES

INVENTORIES

NOTE 6—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. Due to seasonality requirements, PGL and NSG expect interim reductions in LIFO layers to be replenished by year end.

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GOODWILL AND OTHER INTANGIBLE ASSETS

3 Months Ended

Mar. 31, 2012

GOODWILL AND OTHER INTANGIBLE ASSETS

GOODWILL AND OTHER INTANGIBLE ASSETS

NOTE 7—GOODWILL AND OTHER INTANGIBLE ASSETS

We had no material changes to the carrying amount of goodwill during the three months ended March 31, 2012, and 2011.

The identifiable intangible assets other than goodwill listed below are part of other current and long-term assets on the Balance Sheets.

(Millions)	March 31, 2012							December 31, 2011
	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets
Customer-related (1)	$	34.5	$	(25.4	)	$	9.1	$	34.5	$	(24.8	)	$	9.7
Electric contract assets (2)	—		—			—		7.8		(6.6		)	1.2
Patents (3)	7.2		(0.1		)	7.1		7.2		—			7.2
Compressed natural gas fueling contract assets (4)	5.6		(0.6		)	5.0		5.6		(0.3		)	5.3
Renewable energy credits (5)	3.3		—			3.3		2.8		—			2.8
Nonregulated easements (6)	3.8		(0.7		)	3.1		3.8		(0.7		)	3.1
Customer-owned equipment modifications (7)	3.8		(0.3		)	3.5		3.6		(0.2		)	3.4
Emission allowances (8)	1.6		(0.1		)	1.5		1.7		(0.2		)	1.5
Other	0.8		(0.3		)	0.5		1.4		(0.3		)	1.1
Total	$	60.6	$	(27.5	)	$	33.1	$	68.4	$	(33.1	)	$	35.3
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	$	70.8	$	(27.5	)	$	43.3	$	78.6	$	(33.1	)	$	45.5

(1)Includes customer relationship assets associated with PELLC’s former nonregulated retail natural gas and electric operations, MERC’s nonutility ServiceChoice business, 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, 2012, was approximately 10 years.

(2)Represents electric customer contracts acquired in exchange for risk management assets.

(3)Includes the fair value of patents at Pinnacle related to a system for more efficiently compressing natural gas to allow for faster fueling. The remaining amortization period at March 31, 2012, was approximately 18 years.

(4)Represents the fair value of Trillium and Pinnacle compressed natural gas customer fueling contracts acquired in September 2011. The remaining amortization period at March 31, 2012, was approximately 9 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, 2012, of approximately 12 years.

(7)Relates to modifications to customer-owned equipment that allow the end-use customer of a pipeline to accept landfill gas. These intangible assets are amortized on a straight-line basis, with a remaining weighted-average amortization period at March 31, 2012, of approximately 12 years.

(8)Emission allowances do not have a contractual term or expiration date. If the EPA’s Cross State Air Pollution Rule, which was stayed in December 2011, is reinstated, it will affect our ability to use certain existing emission allowances in the future. See Note 11, “Commitments and Contingencies,” for more information.

Amortization expense recorded as a component of nonregulated cost of sales in the statements of income for the three months ended March 31, 2012, and 2011, was $1.6 million and $0.3 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, 2012, and 2011, was $0.7 million and $0.8 million, respectively.

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

	For the year ending December 31
(Millions)	2012		2013		2014		2015		2016
Amortization recorded in nonregulated cost of sales	$	5.9	$	1.8	$	1.4	$	1.3	$	1.1
Amortization recorded in depreciation and amortization expense	2.5		2.0		1.7		1.7		1.5

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LONG-TERM DEBT

3 Months Ended

Mar. 31, 2012

LONG-TERM DEBT

LONG-TERM DEBT

NOTE 9—LONG-TERM DEBT

(Millions)	March 31, 2012			December 31, 2011
WPS (1)	$	722.1		$	722.1
PGL	525.0			525.0
NSG (2)	74.7			74.7
Integrys Energy Group (3)	774.8			774.8
Other term loan (4)	27.0			27.0
Total	2,123.6			2,123.6
Unamortized discount	(1.5		)	(1.6		)
Total debt	2,122.1			2,122.0
Less current portion	(272.0		)	(250.0		)
Total long-term debt	$	1,850.1		$	1,872.0

(1)In December 2012, WPS’s 4.875% Senior Notes will mature. As a result, the $150.0 million balance of these notes was included in current portion of long-term debt on our balance sheets.

In February 2013, WPS’s 3.95% Senior Notes will mature. As a result, the $22.0 million balance of these notes was included in current portion of long-term debt on our March 31, 2012 balance sheet.

(2)In April 2012, NSG bought back its $28.2 million of 5.00% Series M First Mortgage Bonds that were due December 1, 2028.

In the same month, NSG issued $28.0 million of 3.43% Series P First Mortgage Bonds. These bonds are due April 1, 2027.

(3)In December 2012, our 5.375% Unsecured Senior Notes will mature. As a result, the $100.0 million balance of these notes was included in current portion of long-term debt on our balance sheets.

(4)This loan has a floating interest rate that is reset weekly. At March 31, 2012, the interest rate was 0.20%. The loan is to be repaid by April 2021.

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COMMON EQUITY (Details 2) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Numerator:
Net income (loss) from continuing operations	$ 97.8	$ 123.4
Discontinued operations, net of tax	1.9	0.1
Preferred stock dividends of subsidiary	(0.8)	(0.8)
Net income attributed to common shareholders	$ 98.9	$ 122.7
Denominator:
Average shares of common stock - basic	78.6	78.3
Effect of dilutive securities - Stock-based compensation (in shares)	0.4	0.3
Effect of dilutive securities - Deferred compensation (in shares)	0.2
Average shares of common stock - diluted	79.2	78.6
Earnings (Loss) per common share
Basic (in dollars per share)	$ 1.26	$ 1.57
Diluted (in dollars per share)	$ 1.25	$ 1.56
Out-of-the-money stock options
Disclosure of antidilutive shares
Antidilutive shares excluded from calculation of diluted earnings per share	0.8	0.8

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COMMON EQUITY (Details 4) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 year
Dividend Payment Restrictions
Total restricted net assets	$ 1,410.5
Equity in undistributed earnings of 50% or less owned investees accounted under equity method investments	$ 112.5
Cumulative period of interest payment deferral on Junior Subordinated Notes (in years)	10
Maximum
Dividend Payment Restrictions
Debt to capitalization ratio required to be maintained (as a percent)	65.00%
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)	50.24%
PGL | Maximum
Dividend Payment Restrictions
Debt to capitalization ratio required to be maintained (as a percent)	65.00%

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COMMON EQUITY (Details) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2012	Dec. 31, 2011
Reconciliation of shares outstanding
Common stock, shares issued	78,287,906	78,287,906
Deferred compensation rabbi trust (in shares)	371,363	382,971
Total common shares outstanding	77,916,543	77,904,935
Average cost of shares in the rabbi trust (in dollars per share)	$ 45.71	$ 44.54

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LONG-TERM DEBT (Tables)

3 Months Ended

Mar. 31, 2012

LONG-TERM DEBT

Disclosure of long-term debt instruments

(Millions)	March 31, 2012			December 31, 2011
WPS (1)	$	722.1		$	722.1
PGL	525.0			525.0
NSG (2)	74.7			74.7
Integrys Energy Group (3)	774.8			774.8
Other term loan (4)	27.0			27.0
Total	2,123.6			2,123.6
Unamortized discount	(1.5		)	(1.6		)
Total debt	2,122.1			2,122.0
Less current portion	(272.0		)	(250.0		)
Total long-term debt	$	1,850.1		$	1,872.0

(1)In December 2012, WPS’s 4.875% Senior Notes will mature. As a result, the $150.0 million balance of these notes was included in current portion of long-term debt on our balance sheets.

In February 2013, WPS’s 3.95% Senior Notes will mature. As a result, the $22.0 million balance of these notes was included in current portion of long-term debt on our March 31, 2012 balance sheet.

(2)In April 2012, NSG bought back its $28.2 million of 5.00% Series M First Mortgage Bonds that were due December 1, 2028.

In the same month, NSG issued $28.0 million of 3.43% Series P First Mortgage Bonds. These bonds are due April 1, 2027.

(3)In December 2012, our 5.375% Unsecured Senior Notes will mature. As a result, the $100.0 million balance of these notes was included in current portion of long-term debt on our balance sheets.

(4)This loan has a floating interest rate that is reset weekly. At March 31, 2012, the interest rate was 0.20%. The loan is to be repaid by April 2021.

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GOODWILL AND OTHER INTANGIBLE ASSETS (Details) (USD $) In Millions, unless otherwise specified			3 Months Ended							3 Months Ended		3 Months Ended				3 Months Ended		3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2012 Nonregulated cost of sales	Mar. 31, 2011 Nonregulated cost of sales	Mar. 31, 2012 Depreciation and amortization	Mar. 31, 2011 Depreciation and amortization	Mar. 31, 2012 Customer-related year	Dec. 31, 2011 Customer-related	Dec. 31, 2011 Electric contract assets	Mar. 31, 2012 Patents year	Dec. 31, 2011 Patents	Mar. 31, 2012 Compressed natural gas fueling contract assets year	Dec. 31, 2011 Compressed natural gas fueling contract assets	Mar. 31, 2012 Renewable energy credits	Dec. 31, 2011 Renewable energy credits	Mar. 31, 2012 Nonregulated easements year	Dec. 31, 2011 Nonregulated easements	Mar. 31, 2012 Customer-owned equipment modifications year	Dec. 31, 2011 Customer-owned equipment modifications	Mar. 31, 2012 Emission allowances	Dec. 31, 2011 Emission allowances	Mar. 31, 2012 Other amortized intangible assets	Dec. 31, 2011 Other amortized intangible assets	Mar. 31, 2012 Trade name MGU	Dec. 31, 2011 Trade name MGU	Mar. 31, 2012 Trade name Trillium	Dec. 31, 2011 Trade name Trillium	Mar. 31, 2012 Trade name Pinnacle CNG Systems	Dec. 31, 2011 Trade name Pinnacle CNG Systems
Amortized intangible assets
Amortized intangible assets, carrying amount, gross	$ 60.6	$ 68.4					$ 34.5	$ 34.5	$ 7.8	$ 7.2	$ 7.2	$ 5.6	$ 5.6	$ 3.3	$ 2.8	$ 3.8	$ 3.8	$ 3.8	$ 3.6	$ 1.6	$ 1.7	$ 0.8	$ 1.4
Accumulated amortization of intangible assets	(27.5)	(33.1)					(25.4)	(24.8)	(6.6)	(0.1)		(0.6)	(0.3)			(0.7)	(0.7)	(0.3)	(0.2)	(0.1)	(0.2)	(0.3)	(0.3)
Amortized intangible assets, net	33.1	35.3					9.1	9.7	1.2	7.1	7.2	5.0	5.3	3.3	2.8	3.1	3.1	3.5	3.4	1.5	1.5	0.5	1.1
Weighted-average amortization period (in years)							10			18		9				12		12
Amortization expense			1.6	0.3	0.7	0.8
Unamortized intangible assets
Unamortized intangible asset, carrying amount																								5.2	5.2	3.5	3.5	1.5	1.5
Total intangible assets, gross	70.8	78.6
Total intangible assets	43.3	45.5
Amortization expense for the next five fiscal years
Amortization expense, 2012			5.9		2.5
Amortization expense, 2013			1.8		2.0
Amortization expense, 2014			1.4		1.7
Amortization expense, 2015			1.3		1.7
Amortization expense, 2016			$ 1.1		$ 1.5

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STOCK-BASED COMPENSATION

3 Months Ended

Mar. 31, 2012

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION

NOTE 14—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)	2012		2011
Performance stock rights	$	1.2	$	(0.7	)
Restricted shares and restricted share units	2.1		2.2
Total stock-based compensation expense	$	3.3	$	1.5
Deferred income tax benefit	$	1.3	$	0.6

Compensation cost recognized for stock options during the three months ended March 31, 2012, and 2011, was not significant.

The total compensation cost capitalized for all awards during the three months ended March 31, 2012, and 2011, was not significant.

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, 2012, along with the assumptions incorporated into the valuation model:

	February 2012 Grant
Weighted-average fair value per option	$	6.30
Expected term		5 years
Risk-free interest rate		0.17% - 2.18%
Expected dividend yield		5.28%
Expected volatility		25%

A summary of stock option activity for the three months ended March 31, 2012, and information related to outstanding and exercisable stock options at March 31, 2012, 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, 2011	2,953,630		$	48.09
Granted	279,535		53.24
Exercised	(225,986	)	44.83
Outstanding at March 31, 2012	3,007,179		$	48.82	5.97	$	14.2
Exercisable at March 31, 2012	2,221,968		$	49.24	5.02	$	9.9

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, 2012. This is calculated as the difference between our closing stock price on March 31, 2012, 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, 2012, and 2011, was $2.0 million and $0.6 million, respectively.

As of March 31, 2012, $2.6 million of compensation cost related to unvested and outstanding stock options was expected to be recognized over a weighted-average period of 3.2 years.

Cash received from option exercises during the three months ended March 31, 2012 was $10.1 million, and was not significant for the three months ended March 31, 2011. The actual tax benefit realized for the tax deductions from these option exercises was not significant for the three months ended March 31, 2012, and 2011.

Performance Stock Rights

The fair values of performance stock rights were 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 was estimated using one to three years of historical data. The table below reflects the assumptions used in the valuation of the outstanding grants at March 31:

	2012
Risk-free interest rate	0.32% - 1.27%
Expected dividend yield	5.28% - 5.34%
Expected volatility	21% - 36%

A summary of the activity for the three months ended March 31, 2012, related to performance stock rights accounted for as equity awards is presented below:

	Performance Stock Rights		Weighted-AverageFair Value*
Outstanding at December 31, 2011	135,948		$	46.18
Granted	18,865		52.70
Distributed	(70,598	)	42.93
Adjustment for final payout	(24,804	)	42.93
Outstanding at March 31, 2012	59,411		$	53.48

*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 for awards that have not been elected for deferral into the deferred compensation plan six months prior to the completion of the performance period.

A summary of the activity for the three months ended March 31, 2012, related to performance stock rights accounted for as liability awards is presented below:

	Performance Stock Rights
Outstanding at December 31, 2011	186,215
Granted	75,408
Distributed	(16,001	)
Adjustment for final payout	(5,622	)
Outstanding at March 31, 2012	240,000

The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of March 31, 2012, was $56.22 per performance stock right.

As of March 31, 2012, $5.7 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 2.3 years.

The total intrinsic value of performance stock rights distributed during the three months ended March 31, 2012, and 2011, was $4.7 million and $6.3 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, 2012, and 2011 was $1.9 million and $2.5 million, respectively.

Restricted Shares and Restricted Share Units

During the second quarter of 2011, the last of the outstanding restricted shares vested. Only restricted share units remain outstanding at March 31, 2012.

A summary of the activity related to all restricted share unit awards (equity and liability awards) for the three months ended March 31, 2012, is presented below:

	Restricted ShareUnit Awards		Weighted-AverageGrant Date Fair Value
Outstanding at December 31, 2011	497,722		$	45.21
Granted	188,346		53.24
Dividend equivalents	6,821		47.94
Vested	(193,878	)	45.07
Forfeited	(1,440	)	46.48
Outstanding at March 31, 2012	497,571		$	48.39

As of March 31, 2012, $16.7 million of compensation cost related to these awards was expected to be recognized over a weighted-average period of 3.1 years.

The total intrinsic value of restricted share and restricted share unit awards vested for the three months ended March 31, 2012, and 2011, was $10.4 million and $6.3 million, respectively. The actual tax benefit realized for the tax deductions from the vesting of restricted shares and restricted share units during the three months ended March 31, 2012, and 2011, was $4.2 million and $2.5 million, respectively.

The weighted-average grant date fair value of restricted share units awarded during the three months ended March 31, 2012, and 2011, was $53.24 and $49.40 per share, respectively.

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REGULATORY ENVIRONMENT

3 Months Ended

Mar. 31, 2012

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT

NOTE 19—REGULATORY ENVIRONMENT

Wisconsin

2013 Rate Case

On March 30, 2012, WPS filed an application with the PSCW to increase retail electric and natural gas rates $85.1 million and $12.8 million, respectively, with rates proposed to be effective January 1, 2013. The filing includes a request for a 10.30% return on common equity and a common equity ratio of 52.37% in WPS’s regulatory capital structure. The proposed retail electric and natural gas rate increases for 2013 are primarily being driven by reduced sales, increased fuel costs to generate electricity, increased electric transmission costs, increased costs to maintain the integrity of natural gas pipelines, increased manufactured gas plant cleanup costs, and general inflation.

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 exceed a 2% price variance from costs included in rates, they will be deferred for recovery or refund in a future rate proceeding. The rate order allows for the netting of the 2010 electric decoupling under-collection with the 2011 electric decoupling over-collection, and reflects reduced contributions to the Focus on Energy Program. The rate order also allows for the deferral of direct Cross State Air Pollution Rule (CSAPR) compliance costs, including carrying costs. As of March 31, 2012, WPS deferred $1.3 million of costs related to CSAPR.

2011 Rates

On January 13, 2011, the PSCW issued a final written order for WPS authorizing an electric rate increase of $21.0 million, calculated on a per unit basis. Although the rate order included a lower authorized return on common equity, lower rate base, and other reduced costs, which resulted in lower total revenues and margins, the rate order also projected lower total sales volumes, which led to a rate increase on a per-unit basis. The rate order also included a projected increase in customer counts that did not materialize, which impacts the decoupling calculation as it adjusts for differences between the actual and authorized margin per customer. The $21.0 million electric rate increase included $20.0 million of recovery of prior deferrals, the majority of which related to the recovery of the 2009 electric decoupling deferral. The $21.0 million excluded the impact of a $15.2 million estimated fuel refund (including carrying costs) from 2010. The PSCW rate order also required an $8.3 million decrease in natural gas rates, which included $7.1 million of recovery for the 2009 decoupling deferral. The new rates were effective January 14, 2011, and reflected a 10.30% return on common equity, down from a 10.90% return on common equity in the previous rate order, and a common equity ratio of 51.65% in WPS’s regulatory capital structure.

The order also addressed the new Wisconsin electric fuel rule, which was finalized on March 1, 2011. The new fuel rule was effective retroactive to January 1, 2011. It requires the deferral of under or over-collections of fuel and purchased power costs that exceed a 2% price variance from the cost of fuel and purchased power included in rates. Under or over-collections deferred in the current year will be recovered or refunded in a future rate proceeding.

Michigan

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 settlement required UPPCO to terminate its existing decoupling mechanism, effective December 31, 2011. Additionally, the settlement agreement 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. 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. 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. It is unknown at this time whether the ruling will be appealed.

2011 UPPCO Rates

On December 21, 2010, the MPSC issued an order approving a settlement agreement for UPPCO authorizing a retail electric rate increase of $8.9 million, effective January 1, 2011. The new rates reflected a 10.30% return on common equity and a common equity ratio of 54.86% in UPPCO’s regulatory capital structure. The order required UPPCO to terminate its uncollectibles expense tracking mechanism after the close of December 2010 business, but retained the decoupling mechanism.

Illinois

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 reflect 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 reflect 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. On February 23, 2012, the ICC rejected the rehearing requests filed by PGL, NSG, and certain interveners. Two interveners, including the Illinois Attorney General, filed appeals of the rate order, including the permanent decoupling mechanism.

The Illinois Attorney General filed a motion with the ICC to stay the implementation of the permanent decoupling mechanism or, in the alternative, make collections subject to refund. The ICC denied the motion. However, the ICC issued an amendatory order with unclear language directing PGL and NSG to identify funds, which would be due to them or customers absent a permanent decoupling mechanism, for potential distribution depending on the results of a final appellate court order. PGL, NSG, and the Illinois Attorney General each requested clarification from the ICC regarding this language, but the ICC has not yet ruled and has no deadline or obligation to do so. Under current Illinois precedent, a utility generally cannot be required to reverse amounts previously recovered or refunded prior to an appellate court decision overturning an ICC-approved rate. Generally, any reversal only applies to periods after an appellate court decision. Under the permanent decoupling mechanism, amounts deferred are subject to an annual reconciliation, with recoveries or refunds occurring in April through December of the following calendar year. We expect to recover or refund amounts deferred in 2012 beginning in April 2013. As of March 31, 2012, PGL recorded approximately $12 million and NSG recorded approximately $1 million under the permanent decoupling mechanism as regulatory assets pending future recovery. However, these amounts will change throughout the remainder of 2012 based on actual customer usage. At this time, management believes recovery is probable; however, depending on the nature and timing of any appellate court decision, the ability to ultimately recover or refund amounts under decoupling could be affected. In addition, an appeal of the pilot decoupling order, which was effective March 2008 through February 2012, is pending and, depending on the outcome, could impact the permanent decoupling mechanism.

Rider ICR

On January 21, 2010, the ICC approved a rider mechanism for PGL to earn a return on and recover the costs, above an annual baseline, of the AMRP through a special charge on customers’ bills, known as Rider ICR. The AMRP is a 20-year project that began in 2011 under which PGL is replacing its cast iron and ductile iron pipes with steel and polyethylene pipes. In June 2010, the ICC issued a rehearing order approving PGL’s proposed baseline of $45.28 million with an annual escalation factor. Recovery of costs for the AMRP became effective on April 1, 2011. On September 30, 2011, the Illinois Appellate Court, First District, reversed the ICC’s approval of Rider ICR, concluding it was improper single issue ratemaking. PGL and the ICC filed for leave to appeal with the Illinois Supreme Court, but their requests were denied. In March 2012, the Illinois Appellate Court remanded the matter to the ICC for further proceeding consistent with its September 30, 2011 decision. As a result, it is possible that the ICC may require PGL to refund amounts previously collected from customers under Rider ICR related to deliveries on or after September 30, 2011.

2009 Illinois Legislation

In July 2009, Illinois Senate Bill (SB) 1918 was signed into law. Under SB 1918, PGL and NSG filed a bad debt rider with the ICC in September 2009 to recover or refund the incremental difference between the rate case authorized uncollectible expense and the actual uncollectible expense reported to the ICC each year. The ICC approved the rider in February 2010. SB 1918 also requires a percentage of income payment plan for low-income utility customers, which became a permanent program in the fourth quarter of 2011. Additionally, SB 1918 requires an energy efficiency program to meet specified energy efficiency standards, which the ICC approved in May 2011. The first program year began in  June 2011. Finally, SB 1918 requires an on-bill financing program that PGL and NSG will operate with their energy efficiency program. The program began in October 2011 and allows certain residential customers to borrow funds from a third-party lender to invest in energy saving measures and to pay the funds back over time through a charge on their utility bill.

Minnesota

2011 Rates

On November 30, 2010, MERC filed an application with the MPUC to increase retail natural gas rates by $15.2 million. The filing includes a request for an 11.25% return on common equity and a common equity ratio of 50.20% in MERC’s regulatory capital structure. On January 28, 2011, the MPUC approved an interim rate order authorizing MERC a retail natural gas rate increase of $7.5 million, effective February 1, 2011. The interim rates reflect a 10.21% return on common equity and a common equity ratio of 50.20% in MERC’s regulatory capital structure. On April 2, 2012, the Administrative Law Judge filed a proposed order to increase retail natural gas rates by $10.7 million. The proposed order includes a 9.41% return on common equity and a common equity ratio of 50.48% in MERC’s regulatory capital structure. The interim rate increase is subject to refund pending the final rate order, which is expected in the second half of 2012.

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 for the 16-month transitional period. The remaining amount was considered probable of recovery due to inconsistencies between the FERC’s SECA order and the transmission owners’ compliance filings. Integrys Energy Services protested FERC’s 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 September 30, 2011, the FERC denied rehearing of its order on the Initial Decision. The FERC has not yet issued an order on the compliance filings made by transmission owners.

As of March 31, 2012, Integrys Energy Services expected to receive future refunds of $3.8 million. Once the orders on compliance filings are issued, refunds will be made. Any refunds will include interest for the period from payment to refund.

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INVESTMENT IN ATC (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Changes in equity method investments
Equity method investments balance at beginning of period	$ 476.3
Add: Equity in net income	21.1	19.4
Add: Capital contributions	(10.4)	(6.2)
Equity method investments balance at end of period	490.6
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	439.4	416.3
Add: Equity in net income	20.8	19.2
Add: Capital contributions	3.4	3.4
Less: Dividends received	16.7	16.2
Equity method investments balance at end of period	$ 446.9	$ 422.7

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SEGMENTS OF BUSINESS (Tables)

3 Months Ended

Mar. 31, 2012

SEGMENTS 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, 2012
External revenues	$	664.0		$	307.0		$	—	$	971.0		$	272.8		$	7.5		$	—		$	1,251.3
Intersegment revenues	1.7			—			—		1.7			0.2			0.7			(2.6		)	—
Depreciation and amortization expense	32.4			22.0			—		54.4			2.9			5.5			(0.1		)	62.7
Earnings in 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			0.6			12.9			(4.2		)	30.5
Provision (benefit) for income taxes	51.5			10.2			7.5		69.2			(12.9		)	(9.5		)	—			46.8
Net income (loss) from continuing operations	78.7			25.0			13.3		117.0			(20.1		)	0.9			—			97.8
Discontinued operations	—			—			—		—			—			1.9			—			1.9
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

	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, 2011
External revenues	$	851.3		$	317.4		$	—	$	1,168.7		$	455.2	$	3.2		$	—		$	1,627.1
Intersegment revenues	2.1			5.2			—		7.3			0.3		0.4			(8.0		)	—
Depreciation and amortization expense	31.2			22.1			—		53.3			3.3		5.8			(0.1		)	62.3
Earnings in equity method investments	—			—			19.2		19.2			—		0.2			—			19.4
Miscellaneous income	0.1			0.3			—		0.4			0.9		6.0			(5.5		)	1.8
Interest expense	12.4			12.0			—		24.4			0.5		15.4			(5.5		)	34.8
Provision (benefit) for income taxes	52.2			11.8			7.8		71.8			5.6		(5.7		)	—			71.7
Net income (loss) from continuing operations	77.4			25.7			11.4		114.5			10.7		(1.8		)	—			123.4
Discontinued operations	—			—			—		—			0.1		—			—			0.1
Preferred stock dividends of subsidiary	(0.2		)	(0.6		)	—		(0.8		)	—		—			—			(0.8		)
Net income (loss) attributed to common shareholders	77.2			25.1			11.4		113.7			10.8		(1.8		)	—			122.7

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CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Assets
Cash and cash equivalents	$ 42.3	$ 28.1
Collateral on deposit	64.2	50.9
Accounts receivable and accrued unbilled revenues, net of reserves of $43.4 and $47.1, respectively	669.7	737.7
Inventories	125.1	252.3
Assets from risk management activities	266.2	227.2
Regulatory assets	132.8	125.1
Deferred income taxes	101.6	94.2
Prepaid taxes	144.3	209.6
Other current assets	87.5	78.2
Current assets	1,633.7	1,803.3
Property, plant, and equipment, net of accumulated depreciation of $3,057.7 and $3,018.7, respectively	5,259.0	5,199.1
Regulatory assets	1,655.4	1,658.5
Assets from risk management activities	56.6	64.4
Equity method investments	490.6	476.3
Goodwill	658.3	658.4
Other long-term assets	125.4	123.2
Total assets	9,879.0	9,983.2
Liabilities and Equity
Short-term debt	305.5	303.3
Current portion of long-term debt	272.0	250.0
Accounts payable	331.2	426.6
Liabilities from risk management activities	400.0	311.6
Accrued taxes	75.4	70.5
Regulatory liabilities	96.5	67.5
Temporary LIFO liquidation credit	36.7
Other current liabilities	198.1	217.2
Current liabilities	1,715.4	1,646.7
Long-term debt	1,850.1	1,872.0
Deferred income taxes	1,108.7	1,070.7
Deferred investment tax credits	43.7	44.0
Regulatory liabilities	334.2	332.5
Environmental remediation liabilities	609.5	615.1
Pension and other postretirement benefit obligations	514.0	749.3
Liabilities from risk management activities	109.9	102.0
Asset retirement obligations	402.3	397.2
Other long-term liabilities	144.0	141.1
Long-term liabilities	5,116.4	5,323.9
Commitments and contingencies
Common stock - $1 par value; 200,000,000 shares authorized; 78,287,906 shares issued; 77,916,543 shares outstanding	78.3	78.3
Additional paid-in capital	2,566.5	2,579.1
Retained earnings	409.2	363.6
Accumulated other comprehensive loss	(41.0)	(42.5)
Shares in deferred compensation trust	(17.0)	(17.1)
Total common shareholders' equity	2,996.0	2,961.4
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	$ 9,879.0	$ 9,983.2

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RISK MANAGEMENT ACTIVITIES

3 Months Ended

Mar. 31, 2012

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, 2012
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Utility Segments
Non-hedge derivatives
Natural gas contracts	Current	$	5.2	$	43.9
Natural gas contracts	Long-term	0.3		9.2
Financial transmission rights (FTRs)	Current	1.0		0.1
Petroleum product contracts	Current	0.4		—
Coal contract	Current	—		5.6
Coal contract	Long-term	—		7.8
Cash flow hedges
Natural gas contracts	Current	—		1.2
Natural gas contracts	Long-term	—		0.2
Nonregulated Segments
Non-hedge derivatives
Natural gas contracts	Current	121.2		120.4
Natural gas contracts	Long-term	22.3		20.7
Electric contracts	Current	138.2		228.6
Electric contracts	Long-term	34.0		72.0
Foreign exchange contracts	Current	0.2		0.2
	Current	266.2		400.0
	Long-term	56.6		109.9
Total		$	322.8	$	509.9

*All derivatives are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and sales exception. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

		December 31, 2011
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Utility Segments
Non-hedge derivatives
Natural gas contracts	Current	$	9.1	$	35.4
Natural gas contracts	Long-term	0.1		8.2
FTRs	Current	2.3		0.1
Petroleum product contracts	Current	0.1		—
Coal contract	Current	—		2.5
Coal contract	Long-term	—		4.4
Cash flow hedges
Natural gas contracts	Current	—		0.9
Natural gas contracts	Long-term	—		0.2
Nonregulated Segments
Non-hedge derivatives
Natural gas contracts	Current	121.6		120.5
Natural gas contracts	Long-term	41.9		40.5
Electric contracts	Current	93.9		152.0
Electric contracts	Long-term	22.4		48.7
Foreign exchange contracts	Current	0.2		0.2
	Current	227.2		311.6
	Long-term	64.4		102.0
Total		$	291.6	$	413.6

*All derivatives are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and sales exception. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

The following table shows our cash collateral positions:

(Millions)	March 31, 2012		December 31, 2011
Cash collateral provided to others	$	64.2	$	50.9
Cash collateral received from others *	1.8		2.3

*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, 2012		December 31, 2011
Integrys Energy Services	$	231.4	$	193.8
Utility segments	52.9		39.1

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, 2012		December 31, 2011
Collateral that would have been required:
Integrys Energy Services	$	281.7	$	272.3
Utility segments	42.5		28.7
Collateral already satisfied:
Integrys Energy Services — Letters of credit	11.0		11.0
Collateral remaining:
Integrys Energy Services	270.7		261.3
Utility segments	42.5		28.7

Utility Segments

Non-Hedge Derivatives

Utility derivatives include natural gas purchase contracts, a coal purchase contract, 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 non-hedge derivative contracts:

	March 31, 2012			December 31, 2011
	Purchases	Sales	Other Transactions	Purchases	Other Transactions
Natural gas (millions of therms)	755.5	0.3	N/A	1,122.7	N/A
FTRs (millions of kilowatt-hours)	N/A	N/A	1,911.0	N/A	5,077.5
Petroleum products (barrels)	51,872.0	N/A	N/A	46,872.0	N/A
Coal contract (millions of tons)	3.9	N/A	N/A	4.1	N/A

The tables below show the unrealized gains (losses) recorded related to non-hedge derivatives at the utilities:

		Three Months Ended March 31
(Millions)	Financial Statement Presentation	2012			2011
Natural gas contracts	Balance Sheet — Regulatory assets (current)	$	(6.4	)	$	11.2
Natural gas contracts	Balance Sheet — Regulatory assets (long-term)	(0.8		)	1.6
Natural gas contracts	Balance Sheet — Regulatory liabilities (current)	(3.7		)	(0.1		)
Natural gas contracts	Balance Sheet — Regulatory liabilities (long-term)	0.1			0.1
Natural gas contracts	Income Statement — Utility cost of fuel, natural gas, and purchased power	0.1			0.1
FTRs	Balance Sheet — Regulatory assets (current)	0.4			0.1
FTRs	Balance Sheet — Regulatory liabilities (current)	(0.3		)	(1.2		)
Petroleum product contracts	Balance Sheet — Regulatory assets (current)	0.1			—
Petroleum product contracts	Balance Sheet — Regulatory liabilities (current)	0.1			0.4
Petroleum product contracts	Income Statement — Operating and maintenance expense	0.1			0.5
Coal contract	Balance Sheet — Regulatory assets (current)	(3.1		)	(0.5		)
Coal contract	Balance Sheet — Regulatory assets (long-term)	(3.5		)	(3.2		)
Coal contract	Balance Sheet — Regulatory liabilities (long-term)	—			(3.7		)

Nonregulated Segments

Non-Hedge 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.

In the next 12 months, pre-tax losses of $0.9 million and $4.5 million related to the 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.

Integrys Energy Services had the following notional volumes of outstanding non-hedge derivative contracts:

	March 31, 2012		December 31, 2011
(Millions)	Purchases	Sales	Purchases	Sales
Commodity contracts
Natural gas (therms)	885.3	713.3	959.2	797.1
Electric (kilowatt-hours)	38,083.7	23,063.4	34,405.7	20,374.0
Foreign exchange contracts (Canadian dollars)	2.6	2.6	4.2	4.2

Gains (losses) related to non-hedge derivatives are recognized currently in earnings, as shown in the tables below:

		Three Months Ended March 31
(Millions)	Income Statement Presentation	2012			2011
Natural gas contracts	Nonregulated revenue	$	4.0		$	8.1
Natural gas contracts	Nonregulated revenue (reclassified from accumulated OCI) *	(1.2		)	(0.3		)
Electric contracts	Nonregulated revenue	(68.6		)	(1.0		)
Electric contracts	Nonregulated revenue (reclassified from accumulated OCI) *	(0.7		)	0.2
Total		$	(66.5	)	$	7.0

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

Fair Value Hedges

At PELLC, an interest rate swap designated as a fair value hedge was used to hedge changes in the fair value of $50.0 million of the $325.0 million Series A 6.9% notes. The interest rate swap and the notes were settled in January 2011. The changes in the fair value of this hedge were recognized in earnings, as were the changes in fair value of the hedged item. Unrealized gains (losses) related to the fair value hedge and the related hedged item are shown in the table below:

		Three Months Ended
(Millions)	Income Statement Presentation	March 31, 2011
Interest rate swap	Interest expense	$	(0.9	)
Debt hedged by swap	Interest expense	0.9
Total		$	—

Cash Flow Hedges

Prior to July 1, 2011, Integrys Energy Services designated derivative contracts such as futures, forwards, and swaps as accounting hedges under GAAP. These contracts are used to manage commodity price risk associated with customer contracts.

The tables below show the amounts related to cash flow hedges recorded in OCI and in earnings:

Unrealized Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
(Millions)	Three Months Ended March 31, 2011
Natural gas contracts	$	1.2
Electric contracts	(4.6		)
Total	$	(3.4	)

Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
		Three Months Ended March 31
(Millions)	Income Statement Presentation	2012			2011
Settled/Realized
Natural gas contracts	Nonregulated revenue	$	—		$	(8.6	)
Electric contracts	Nonregulated revenue	—			(4.1		)
Interest rate swaps *	Interest expense	(0.3		)	(0.3		)
Hedge Designation Discontinued
Natural gas contracts	Nonregulated revenue	—			(0.3		)
Total		$	(0.3	)	$	(13.3	)

*In May 2010, we entered into interest rate swaps that were designated as cash flow hedges to hedge the variability in forecasted interest payments on a debt issuance. These swaps were terminated when the related debt was issued in November 2010. Amounts remaining in accumulated OCI are being reclassified to interest expense over the life of the related debt.

Gain Recognized in Income on Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing)
(Millions)	Income Statement Presentation	Three Months Ended March 31, 2011
Natural gas contracts	Nonregulated revenue	$	0.8
Electric contracts	Nonregulated revenue	0.3
Total		$	1.1

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GUARANTEES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 year
Guarantees
Total guarantees	$ 747.2
Guarantees expiring in less than 1 year	476.8
Guarantees expiring within 1 to 3 years	38.4
Guarantees with expiration over 3 years from balance sheet date	232.0
Integrys Energy Services | Parental guarantees
Guarantees
Total guarantees	559.0
Guarantee exposure related to open transactions	319.3
Guarantees supporting commodity transactions
Guarantees
Total guarantees	623.9
Guarantees expiring in less than 1 year	407.7
Guarantees expiring within 1 to 3 years	6.9
Guarantees with expiration over 3 years from balance sheet date	209.3
Guarantees supporting commodity transactions | Integrys Energy Services | Parental guarantees
Guarantees
Total guarantees	456.2
Guarantees supporting commodity transactions | MERC
Guarantees
Total guarantees	111.8
Guarantees supporting commodity transactions | MGU
Guarantees
Total guarantees	48.9
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	66.9
Guarantees expiring in less than 1 year	35.3
Guarantees expiring within 1 to 3 years	31.5
Guarantees with expiration over 3 years from balance sheet date	0.1
Standby letters of credit | Integrys Energy Services | Parental guarantees
Guarantees
Total guarantees	64.1
Standby letters of credit | UPPCO, WPS, MGU, NSG, MERC, PGL, and Pinnacle CNG Systems
Guarantees
Total guarantees	2.8
Surety bonds
Guarantees
Total guarantees	13.8
Guarantees expiring in less than 1 year	13.8
Surety bonds | Integrys Energy Services | Parental guarantees
Guarantees
Total guarantees	3.2
Other guarantees
Guarantees
Total guarantees	42.6
Guarantees expiring in less than 1 year	20.0
Guarantees with expiration over 3 years from balance sheet date	22.6
Other guarantees | Integrys Energy Services | United States Wholesale Electric Marketing and Trading Business
Guarantees
Total guarantees	20.0
Period of retention of counter party payment default risk (in years)	2
Percentage of counterparties transferred in the transaction	50.00%
Other guarantees | Integrys Energy Services | Texas Retail Electric Marketing Business
Guarantees
Total guarantees	10.0
Other guarantees | Integrys Energy Services | Parental guarantees
Guarantees
Total guarantees	35.5
Environmental indemnification | Integrys Energy Services | Sale of Stoneman generation facility
Guarantees
Total guarantees	5.0
Indemnification and workers' compensation coverage
Guarantees
Total guarantees	$ 7.6

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FAIR VALUE (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Assets
Risk Management Assets	$ 322.8	$ 291.6
Liabilities
Risk Management Liabilities	509.9	413.6
Level 1 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	103.2	92.1
Liabilities
Risk Management Liabilities	130.7	114.9
Level 2 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	193.4	184.6
Liabilities
Risk Management Liabilities	329.5	275.9
Level 3 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	26.2	14.9
Liabilities
Risk Management Liabilities	49.7	22.8
Total, Fair value | Fair value measurements on a recurring basis
Assets
Risk Management Assets	322.8	291.6
Liabilities
Risk Management Liabilities	509.9	413.6
Utility Segments | Natural gas contracts | Level 1 | Fair value measurements on a recurring basis
Assets
Risk Management Assets		0.1
Liabilities
Risk Management Liabilities	1.6	5.5
Utility Segments | Natural gas contracts | Level 2 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	5.5	9.1
Liabilities
Risk Management Liabilities	52.9	39.2
Utility Segments | Natural gas contracts | Total, Fair value | Fair value measurements on a recurring basis
Assets
Risk Management Assets	5.5	9.2
Liabilities
Risk Management Liabilities	54.5	44.7
Utility Segments | FTRs | Level 3 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	1.0	2.3
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	2.3
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	0.4	0.1
Utility Segments | Petroleum product contracts | Total, Fair value | Fair value measurements on a recurring basis
Assets
Risk Management Assets	0.4	0.1
Utility Segments | Coal contract | Level 3 | Fair value measurements on a recurring basis
Liabilities
Risk Management Liabilities	13.4	6.9
Utility Segments | Coal contract | Total, Fair value | Fair value measurements on a recurring basis
Liabilities
Risk Management Liabilities	13.4	6.9
Nonregulated Segments | Natural gas contracts | Level 1 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	41.5	50.7
Liabilities
Risk Management Liabilities	47.7	55.0
Nonregulated Segments | Natural gas contracts | Level 2 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	90.9	104.1
Liabilities
Risk Management Liabilities	93.2	105.6
Nonregulated Segments | Natural gas contracts | Level 3 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	11.1	8.7
Liabilities
Risk Management Liabilities	0.2	0.4
Nonregulated Segments | Natural gas contracts | Total, Fair value | Fair value measurements on a recurring basis
Assets
Risk Management Assets	143.5	163.5
Liabilities
Risk Management Liabilities	141.1	161.0
Nonregulated Segments | Electric contracts | Level 1 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	61.3	41.2
Liabilities
Risk Management Liabilities	81.2	54.2
Nonregulated Segments | Electric contracts | Level 2 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	96.8	71.2
Liabilities
Risk Management Liabilities	183.4	131.1
Nonregulated Segments | Electric contracts | Level 3 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	14.1	3.9
Liabilities
Risk Management Liabilities	36.0	15.4
Nonregulated Segments | Electric contracts | Total, Fair value | Fair value measurements on a recurring basis
Assets
Risk Management Assets	172.2	116.3
Liabilities
Risk Management Liabilities	300.6	200.7
Nonregulated Segments | Foreign exchange contracts | Level 1 | Fair value measurements on a recurring basis
Liabilities
Risk Management Liabilities	0.2	0.2
Nonregulated Segments | Foreign exchange contracts | Level 2 | Fair value measurements on a recurring basis
Assets
Risk Management Assets	0.2	0.2
Nonregulated Segments | Foreign exchange contracts | Total, Fair value | Fair value measurements on a recurring basis
Assets
Risk Management Assets	0.2	0.2
Liabilities
Risk Management Liabilities	$ 0.2	$ 0.2

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SEGMENTS OF BUSINESS

3 Months Ended

Mar. 31, 2012

SEGMENTS OF BUSINESS

SEGMENTS OF BUSINESS

NOTE 20—SEGMENTS OF BUSINESS

At March 31, 2012, we reported five segments, which are described below.

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

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

· The electric transmission investment segment includes our approximate 34% ownership interest in ATC. ATC is a federally regulated electric transmission company with operations in Wisconsin, Michigan, Minnesota, and Illinois.

· Integrys Energy Services is a diversified nonregulated retail energy supply and services company that primarily sells electricity and natural gas to commercial, industrial, and residential customers 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 and the PELLC holding company, along with any nonutility activities at WPS, UPPCO, PGL, NSG, MERC, MGU, and IBS. The operations of ITF were included in this segment beginning on September 1, 2011, when we acquired Trillium USA and Pinnacle CNG Systems.

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, 2012
External revenues	$	664.0		$	307.0		$	—	$	971.0		$	272.8		$	7.5		$	—		$	1,251.3
Intersegment revenues	1.7			—			—		1.7			0.2			0.7			(2.6		)	—
Depreciation and amortization expense	32.4			22.0			—		54.4			2.9			5.5			(0.1		)	62.7
Earnings in 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			0.6			12.9			(4.2		)	30.5
Provision (benefit) for income taxes	51.5			10.2			7.5		69.2			(12.9		)	(9.5		)	—			46.8
Net income (loss) from continuing operations	78.7			25.0			13.3		117.0			(20.1		)	0.9			—			97.8
Discontinued operations	—			—			—		—			—			1.9			—			1.9
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

	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, 2011
External revenues	$	851.3		$	317.4		$	—	$	1,168.7		$	455.2	$	3.2		$	—		$	1,627.1
Intersegment revenues	2.1			5.2			—		7.3			0.3		0.4			(8.0		)	—
Depreciation and amortization expense	31.2			22.1			—		53.3			3.3		5.8			(0.1		)	62.3
Earnings in equity method investments	—			—			19.2		19.2			—		0.2			—			19.4
Miscellaneous income	0.1			0.3			—		0.4			0.9		6.0			(5.5		)	1.8
Interest expense	12.4			12.0			—		24.4			0.5		15.4			(5.5		)	34.8
Provision (benefit) for income taxes	52.2			11.8			7.8		71.8			5.6		(5.7		)	—			71.7
Net income (loss) from continuing operations	77.4			25.7			11.4		114.5			10.7		(1.8		)	—			123.4
Discontinued operations	—			—			—		—			0.1		—			—			0.1
Preferred stock dividends of subsidiary	(0.2		)	(0.6		)	—		(0.8		)	—		—			—			(0.8		)
Net income (loss) attributed to common shareholders	77.2			25.1			11.4		113.7			10.8		(1.8		)	—			122.7

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ADVERTISING COSTS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 year	Mar. 31, 2011
ADVERTISING COSTS
Capitalized direct-response advertising costs, net of accumulated amortization	$ 4.4
Period of amortization of direct-response advertising costs over estimated period of benefit (in years)	2
Amortization of direct-response advertising	1.0
Other advertising expense	$ 1.7	$ 1.9

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STOCK-BASED COMPENSATION (Tables)

3 Months Ended

Mar. 31, 2012

STOCK-BASED COMPENSATION

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

(Millions)	2012		2011
Performance stock rights	$	1.2	$	(0.7	)
Restricted shares and restricted share units	2.1		2.2
Total stock-based compensation expense	$	3.3	$	1.5
Deferred income tax benefit	$	1.3	$	0.6

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

	February 2012 Grant
Weighted-average fair value per option	$	6.30
Expected term		5 years
Risk-free interest rate		0.17% - 2.18%
Expected dividend yield		5.28%
Expected volatility		25%

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, 2011	2,953,630		$	48.09
Granted	279,535		53.24
Exercised	(225,986	)	44.83
Outstanding at March 31, 2012	3,007,179		$	48.82	5.97	$	14.2
Exercisable at March 31, 2012	2,221,968		$	49.24	5.02	$	9.9

Disclosure of performance stock rights assumptions

	2012
Risk-free interest rate	0.32% - 1.27%
Expected dividend yield	5.28% - 5.34%
Expected volatility	21% - 36%

Summary of the activity related to equity performance stock rights

	Performance Stock Rights		Weighted-AverageFair Value*
Outstanding at December 31, 2011	135,948		$	46.18
Granted	18,865		52.70
Distributed	(70,598	)	42.93
Adjustment for final payout	(24,804	)	42.93
Outstanding at March 31, 2012	59,411		$	53.48

*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 for awards that have not been elected for deferral into the deferred compensation plan six months prior to the completion of the performance period.

Summary of the activity related to liability performance stock rights

	Performance Stock Rights
Outstanding at December 31, 2011	186,215
Granted	75,408
Distributed	(16,001	)
Adjustment for final payout	(5,622	)
Outstanding at March 31, 2012	240,000

Summary of the activity related to restricted share and restricted share unit awards

	Restricted ShareUnit Awards		Weighted-AverageGrant Date Fair Value
Outstanding at December 31, 2011	497,722		$	45.21
Granted	188,346		53.24
Dividend equivalents	6,821		47.94
Vested	(193,878	)	45.07
Forfeited	(1,440	)	46.48
Outstanding at March 31, 2012	497,571		$	48.39

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EMPLOYEE BENEFIT PLANS

3 Months Ended

Mar. 31, 2012

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

NOTE 13—EMPLOYEE BENEFIT PLANS

As of February 16, 2012, our defined benefit pension plans were closed to all new hires.

The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheet) for our benefit plans for the three months ended March 31:

	Pension Benefits						Other Postretirement Benefits
(Millions)	2012			2011			2012			2011
Service cost	$	12.4		$	11.3		$	5.5		$	5.0
Interest cost	19.8			20.5			7.2			7.7
Expected return on plan assets	(27.1		)	(24.7		)	(7.0		)	(5.0		)
Amortization of transition obligation	—			—			0.1			0.1
Amortization of prior service cost (credit)	1.2			1.3			(0.9		)	(0.9		)
Amortization of net actuarial loss	8.3			4.7			1.6			1.1
Net periodic benefit cost	$	14.6		$	13.1		$	6.5		$	8.0

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. We contributed $171.5 million to our pension plans and $75.1 million to our other postretirement benefit plans during the three months ended March 31, 2012. We expect to contribute an additional $3.8 million to our pension plans and $39.1 million to our other postretirement benefit plans during the remainder of 2012, dependent upon various factors affecting us, including our liquidity position and tax law changes.