Integrys Holding (TEG) 10-Q 2 May 14 2014 Q1 Quarterly report Financial data

DOCUMENT_AND_ENTITY_INFORMATIO

DOCUMENT AND ENTITY INFORMATION	3 Months Ended
	Mar. 31, 2014	Apr. 30, 2014
Document and Entity Information	'	'
Entity Registrant Name	'INTEGRYS ENERGY GROUP, INC.	'
Entity Central Index Key	'0000916863	'
Document Type	'10-Q	'
Document Period End Date	31-Mar-14	'
Amendment Flag	'false	'
Current Fiscal Year End Date	'--12-31	'
Entity Current Reporting Status	'Yes	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	79,963,091
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q1	'

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Income Statement [Abstract]	'	'
Utility revenues	$1,616.70	$1,123.80
Nonregulated revenues	1,308.20	554.4
Total revenues	2,924.90	1,678.20
Utility cost of fuel, natural gas, and purchased power	960.2	565.1
Nonregulated cost of sales	1,247.50	436.8
Operating and maintenance expense	364.6	295.1
Depreciation and amortization expense	71.3	60.9
Taxes other than income taxes	28.1	27.2
Operating income	253.2	293.1
Earnings from equity method investments	22.9	22.3
Miscellaneous income	6	5.7
Interest expense	39.1	29.3
Other expense	-10.2	-1.3
Income before taxes	243	291.8
Provision for income taxes	89.8	109.6
Net income from continuing operations	153.2	182.2
Discontinued operations, net of tax	-0.1	6.1
Net income	153.1	188.3
Preferred stock dividends of subsidiary	-0.8	-0.8
Noncontrolling interest in subsidiaries	0.1	0
Net income attributed to common shareholders	$152.40	$187.50
Average shares of common stock	'	'
Basic (in shares)	80.2	78.7
Diluted (in shares)	80.5	79.3
Earnings per common share (basic)	'	'
Net income from continuing operations (in dollars per share)	$1.90	$2.30
Discontinued operations, net of tax (in dollars per share)	$0	$0.08
Earnings per common share (basic) (in dollars per share)	$1.90	$2.38
Earnings per common share (diluted)	'	'
Net income from continuing operations (in dollars per share)	$1.89	$2.29
Discontinued operations, net of tax (in dollars per share)	$0	$0.08
Earnings per common share (diluted) (in dollars per share)	$1.89	$2.37
Dividends per common share declared (in dollars per share)	$0.68	$0.68

CONDENSED_CONSOLIDATED_STATEME1

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Statement of Comprehensive Income [Abstract]	'	'
Net income	$153.10	$188.30
Cash flow hedges	'	'
Unrealized net gains arising during period, net of tax of $ – million and $ – million, respectively	0	0.1
Reclassification of net (gains) losses to net income, net of tax of $0.9 million and $0.6 million, respectively	-0.6	0.9
Cash flow hedges, net	-0.6	1
Defined benefit plans	'	'
Pension and other postretirement benefit costs arising during period, net of tax of $(0.1) million and $ – million, respectively	-0.1	0
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.3 million and $0.4 million, respectively	0.3	0.6
Defined benefit plans, net	0.2	0.6
Other comprehensive income (loss), net of tax	-0.4	1.6
Comprehensive income	152.7	189.9
Preferred stock dividends of subsidiary	-0.8	-0.8
Noncontrolling interest in subsidiaries	0.1	0
Comprehensive income attributed to common shareholders	$152	$189.10

CONDENSED_CONSOLIDATED_STATEME2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Statement of Comprehensive Income [Abstract]	'	'
Unrealized net gains arising during period, tax	$0	$0
Reclassification of net (gains) losses to net income, tax	0.9	0.6
Pension and other postretirement benefit costs arising during period, tax	-0.1	0
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, tax	$0.30	$0.40

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Assets	'	'
Cash and cash equivalents	$56.60	$22.30
Collateral on deposit	74.4	37.4
Accounts receivable and accrued unbilled revenues, net of reserves of $61.9 and $49.4, respectively	1,543.80	1,037
Inventories	134.9	253.1
Assets from risk management activities	269.9	239.5
Regulatory assets	238.8	127.4
Assets held for sale	286.7	272.6
Deferred income taxes	0	31.4
Prepaid taxes	74.5	146.9
Other current assets	37.5	50
Current assets	2,717.10	2,217.60
Property, plant, and equipment, net of accumulated depreciation of $3,283.5 and $3,236.9, respectively	6,301.20	6,216.70
Regulatory assets	1,346.70	1,361.40
Assets from risk management activities	60.3	75.4
Equity method investments	548.1	540.9
Goodwill	662.1	662.1
Other long-term assets	166.7	169.4
Total assets	11,802.20	11,243.50
Liabilities and Equity	'	'
Short-term debt	321.9	326
Current portion of long-term debt	100	100
Accounts payable	864.9	604.8
Liabilities from risk management activities	175.8	163.8
Accrued taxes	111.4	80.9
Regulatory liabilities	149.9	101.1
Temporary LIFO liquidation credit	150.9	0
Liabilities held for sale	36.7	49.1
Deferred income taxes	12.8	0
Other current liabilities	218.6	228.8
Current liabilities	2,142.90	1,654.50
Long-term debt	2,956.20	2,956.20
Deferred income taxes	1,439.90	1,390.30
Deferred investment tax credits	57.6	57.6
Regulatory liabilities	438.8	383.7
Environmental remediation liabilities	588.4	600
Pension and other postretirement benefit obligations	95.6	200.8
Liabilities from risk management activities	46.2	62.8
Asset retirement obligations	497	491
Other long-term liabilities	133.6	133.2
Long-term liabilities	6,253.30	6,275.60
Commitments and contingencies	'	'
Common stock – $1 par value; 200,000,000 shares authorized; 79,963,091 shares issued; 79,534,371 shares outstanding	80	79.9
Additional paid-in capital	2,653.40	2,660.50
Retained earnings	665	567.1
Accumulated other comprehensive loss	-23.6	-23.2
Shares in deferred compensation trust	-20.8	-23
Total common shareholders’ equity	3,354	3,261.30
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	0.9	1
Total liabilities and equity	$11,802.20	$11,243.50

CONDENSED_CONSOLIDATED_BALANCE1

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]	'	'
Accounts receivable and accrued unbilled revenues, reserves (in dollars)	$61.90	$49.40
Property, plant, and equipment, accumulated depreciation (in dollars)	$3,283.50	$3,236.90
Common stock, par value (in dollars per share)	$1	'
Common stock, shares authorized	200,000,000	'
Common stock, shares issued	79,963,091	79,919,176
Common stock, shares outstanding	79,534,371	79,445,380
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	'

CONDENSED_CONSOLIDATED_STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Operating Activities	'	'
Net income	$153.10	$188.30
Adjustments to reconcile net income to net cash provided by operating activities	'	'
Discontinued operations, net of tax	0.1	-6.1
Depreciation and amortization expense	71.3	60.9
Recoveries and refunds of regulatory assets and liabilities	54.1	16.5
Net unrealized gains on energy contracts	-19.7	-65.2
Bad debt expense	19.3	9.3
Pension and other postretirement expense	7.2	15.9
Pension and other postretirement contributions	-68.6	-63.2
Deferred income taxes and investment tax credits	90.2	68.3
Equity income, net of dividends	-3.9	-4.4
Termination of tolling agreement with Fox Energy Company LLC	0	-50
Other	1.1	6.3
Changes in working capital	'	'
Collateral on deposit	-37	15.4
Accounts receivable and accrued unbilled revenues	-531.5	-182.8
Inventories	121.6	137.9
Other current assets	-71.7	45.4
Accounts payable	272.1	24.7
Temporary LIFO liquidation credit	150.9	83.2
Other current liabilities	54.7	19.2
Net cash provided by operating activities	263.3	319.6
Investing Activities	'	'
Capital expenditures	-159.6	-147
Capital contributions to equity method investments	-5.1	-1.7
Acquisition of Fox Energy Company LLC	0	-391.6
Grant received related to Crane Creek wind project	0	69
Other	1.4	-1.9
Net cash used for investing activities	-163.3	-473.2
Financing Activities	'	'
Short-term debt, net	-4.1	74
Borrowing on term credit facility	0	200
Repayment of long-term debt	0	-22
Proceeds from stock option exercises	0.4	6.4
Shares purchased for stock-based compensation	-9.8	-2
Payment of dividends	'	'
Preferred stock of subsidiary	-0.8	-0.8
Common stock	-54.1	-50.1
Other	-3.7	-8.3
Net cash (used for) provided by financing activities	-72.1	197.2
Change in cash and cash equivalents - continuing operations	27.9	43.6
Change in cash and cash equivalents - discontinued operations	'	'
Net cash provided by (used for) operating activities	6.4	-0.6
Net cash provided by investing activities	0	1.6
Net change in cash and cash equivalents	34.3	44.6
Cash and cash equivalents at beginning of period	22.3	27.4
Cash and cash equivalents at end of period	56.6	72
Supplemental Cash Flow Information	'	'
Cash paid for interest	13.4	4.8
Cash received for income taxes	($62.70)	($1)

FINANCIAL_INFORMATION

FINANCIAL INFORMATION	3 Months Ended
	Mar. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
FINANCIAL INFORMATION	'
	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, 2013. Financial results for an interim period may not give a true indication of results for the year.
	In management’s opinion, these unaudited financial statements include all adjustments necessary for a fair presentation of financial results. All adjustments are normal and recurring, unless otherwise noted. All intercompany transactions have been eliminated in consolidation.
	Reclassification
	Assets and liabilities associated with the pending sale of UPPCO were reclassified as held for sale on our December 31, 2013, balance sheet to be consistent with the current period presentation. See Note 5, Dispositions, for more information on the pending sale of UPPCO.

CASH_AND_CASH_EQUIVALENTS

CASH AND CASH EQUIVALENTS	3 Months Ended
	Mar. 31, 2014
Cash and Cash Equivalents [Abstract]	'
CASH AND CASH EQUIVALENTS	'
	Cash and Cash Equivalents
	Short-term investments with an original maturity of three months or less are reported as cash equivalents.
	Significant noncash transactions were:
		Three Months Ended March 31
	(Millions)	2014		2013
	Construction costs funded through accounts payable	$	92.3	$	59.8
	Equity issued for employee stock ownership plan	1.7		2.7
	Equity issued for stock-based compensation plans	—		16
	Equity issued for reinvested dividends	—		3

RISK_MANAGEMENT_ACTIVITIES

RISK MANAGEMENT ACTIVITIES	3 Months Ended
	Mar. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
RISK MANAGEMENT ACTIVITIES	'
	Risk Management Activities
	The following tables show our assets and liabilities from risk management activities:
					March 31, 2014
	(Millions)		Balance Sheet Presentation (1)		Assets from				Liabilities from
					Risk Management Activities				Risk Management Activities
	Utility Segments
	Nonhedge derivatives
	Natural gas contracts		Current		$	12.3			$	0.3
	Natural gas contracts		Long-term		1				0.1
	Financial transmission rights (FTRs) (2)		Current		0.9				0.2
	Petroleum product contracts		Current		0.1				—
	Coal contracts		Current		—				1.1
	Coal contracts		Long-term		1.8				0.4
	Nonregulated Segments
	Nonhedge derivatives
	Natural gas contracts		Current		56				41.7
	Natural gas contracts		Long-term		20.9				10.9
	Electric contracts		Current		200.8				132.5
	Electric contracts		Long-term		36.6				34.8
			Current		270.1				175.8
			Long-term		60.3				46.2
	Total				$	330.4			$	222
	(1)	We classify assets and liabilities from risk management activities as current or long-term based on the maturities of the underlying contracts.
	(2)	Includes a $0.2 million risk management asset that was classified as held for sale at UPPCO. See Note 5, Dispositions, for more information.
					31-Dec-13
	(Millions)		Balance Sheet Presentation (1)		Assets from				Liabilities from
					Risk Management Activities				Risk Management Activities
	Utility Segments
	Nonhedge derivatives
	Natural gas contracts		Current		$	8.3			$	1
	Natural gas contracts		Long-term		1.8				0.1
	FTRs (2)		Current		2.1				0.3
	Petroleum product contracts		Current		0.1				—
	Coal contracts		Current		—				1.9
	Coal contracts		Long-term		0.2				0.8
	Nonregulated Segments
	Nonhedge derivatives
	Natural gas contracts		Current		57.6				42.9
	Natural gas contracts		Long-term		29.5				18.6
	Electric contracts		Current		172				117.7
	Electric contracts		Long-term		43.9				43.3
			Current		240.1				163.8
			Long-term		75.4				62.8
	Total				$	315.5			$	226.6
	(1)	We classify assets and liabilities from risk management activities as current or long-term based on the maturities of the underlying contracts.
	(2)	Includes a $0.6 million risk management asset that was classified as held for sale at UPPCO. See Note 5, Dispositions, for more information.
	The following tables show the potential effect on our financial position of netting arrangements for recognized derivative assets and liabilities:
			March 31, 2014
	(Millions)		Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements
	Utility segments		$	14.3			$	0.6			$	13.7
	Nonregulated segments		314				193				121
	Total		328.3				193.6				134.7
	Derivative assets not subject to master netting or similar arrangements		2.1								2.1
	Total risk management assets		$	330.4							$	136.8
	Derivative liabilities subject to master netting or similar arrangements
	Utility segments		$	0.6			$	0.6			$	—
	Nonregulated segments		219.8				193				26.8
	Total		220.4				193.6				26.8
	Derivative liabilities not subject to master netting or similar arrangements		1.6								1.6
	Total risk management liabilities		$	222							$	28.4
			31-Dec-13
	(Millions)		Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
Derivative assets subject to master netting or similar arrangements
Utility segments		$	12.3			$	2.1			$	10.2
Nonregulated segments		301.9				178.1				123.8
Total		314.2				180.2				134
Derivative assets not subject to master netting or similar arrangements		1.3								1.3
Total risk management assets		$	315.5							$	135.3
Derivative liabilities subject to master netting or similar arrangements
Utility segments		$	1.4			$	1.4			$	—
Nonregulated segments		222.1				178.1				44
Total		223.5				179.5				44
Derivative liabilities not subject to master netting or similar arrangements		3.1								3.1
Total risk management liabilities		$	226.6							$	47.1
Our master netting and similar arrangements have conditional rights of setoff that can be enforced under a variety of situations, including counterparty default or credit rating downgrade below investment grade. We have trade receivables and trade payables, subject to master netting or similar arrangements, that are not included in the above tables. These amounts may offset (or conditionally offset) the net amounts presented in the above tables.
Financial collateral received or provided is restricted to the extent that it is required per the terms of the related agreements. The following table shows our cash collateral positions:
(Millions)		March 31, 2014				December 31, 2013
Cash collateral provided to others:
Related to contracts under master netting or similar arrangements (1)		$	74.6			$	37.6
Other		1.1				1.1
Cash collateral received from others related to contracts under master netting or similar arrangements (2)		1.5				0.7
(1)	Includes $1.3 million of cash collateral provided to others that was classified as held for sale at UPPCO at March 31, 2014 and December 31, 2013. See Note 5, Dispositions, for more information.
(2)	Reflected in other current liabilities on the balance sheets.
Certain of our derivative and nonderivative commodity instruments contain provisions that could require "adequate assurance" in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The following table shows the aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a liability position:
(Millions)		March 31, 2014				December 31, 2013
Utility segments		$	0.2			$	0.6
Nonregulated segments		58.4				76.7
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, 2014				December 31, 2013
Collateral that would have been required:
Utility segments		$	—			$	—
Nonregulated segments		199.7				197.6
Collateral already satisfied:
Nonregulated segments — Letters of credit		20				4.5
Collateral remaining:
Nonregulated segments		179.7				193.1
Utility Segments
Non-Hedge Derivatives
Utility derivatives include natural gas purchase contracts, coal purchase contracts, financial derivative contracts, and FTRs used to manage electric transmission congestion costs. The electric and natural gas utility segments use financial derivative contracts to manage the risks associated with the market price volatility of natural gas supply costs. In addition, IBS enters into financial derivative contracts on behalf of the utilities to manage the cost of gasoline and diesel fuel used by utility vehicles.
The notional volumes of outstanding derivative contracts at the utilities and IBS were as follows:
		March 31, 2014									December 31, 2013
(Millions, except barrels)		Purchases			Sales			Other Transactions			Purchases	Sales	Other Transactions
Natural gas (therms)		2,438.80			2.1			N/A			3,124.80	29.3	N/A
FTRs (kilowatt-hours)		N/A			N/A			1,448.70			N/A	N/A	3,633.10
Petroleum products (barrels)		113,000.00			20,000.00			N/A			102,811.00	14,000.00	N/A
Coal (tons)		4.3			—			N/A			4.8	—	N/A
The table below shows the unrealized gains (losses) recorded related to derivative contracts at the utilities and IBS:
				Three Months Ended March 31
(Millions)		Financial Statement Presentation		2014				2013
Natural gas		Balance Sheet — Regulatory assets (current)		$	0.9			$	13
Natural gas		Balance Sheet — Regulatory assets (long-term)		(0.2		)		0.8
Natural gas		Balance Sheet — Regulatory liabilities (current)		3.4				5.9
Natural gas		Balance Sheet — Regulatory liabilities (long-term)		(0.4		)		0.8
Natural gas		Income Statement — Operating and maintenance expense		0.2				0.2
FTRs		Balance Sheet — Regulatory assets (current)		0.2				0.2
FTRs		Balance Sheet — Regulatory liabilities (current)		(0.2		)		(0.4		)
Coal		Balance Sheet — Regulatory assets (current)		0.2				1.9
Coal		Balance Sheet — Regulatory assets (long-term)		0.4				2.3
Coal		Balance Sheet — Regulatory liabilities (current)		—				(0.2		)
Coal		Balance Sheet — Regulatory liabilities (long-term)		1.6				(2.2		)
Nonregulated Segments
Nonhedge Derivatives
IES enters into physical and financial derivative contracts that are used to manage commodity price risk primarily associated with retail electric and natural gas customer contracts.
IES had the following notional volumes of outstanding derivative contracts:
		March 31, 2014						December 31, 2013
(Millions)		Purchases			Sales			Purchases			Sales
Commodity contracts
Natural gas (therms)		919.2			774.3			1,199.90			1,065.40
Electric (kilowatt-hours)		40,473.70			25,245.00			49,186.30			30,813.80
Gains (losses) related to derivative contracts are recognized currently in earnings, as shown in the table below:
				Three Months Ended March 31
(Millions)		Income Statement Presentation		2014				2013
Natural gas		Nonregulated revenue		$	(36.9	)		$	3.4
Natural gas		Nonregulated cost of sales		33				(1.6		)
Natural gas		Nonregulated revenue (reclassified from accumulated OCI) *		—				(0.1		)
Electric		Nonregulated revenue		160.3				64
Electric		Nonregulated cost of sales		0.6				—
Electric		Nonregulated revenue (reclassified from accumulated OCI) *		—				(1.0		)
Total				$	157			$	64.7
*	Represents amounts reclassified from accumulated other comprehensive loss (OCI) related to cash flow hedges that were dedesignated in prior periods.

ACQUISITIONS

ACQUISITIONS	3 Months Ended
	Mar. 31, 2014
Business Combinations [Abstract]	'
ACQUISITIONS	'
	Acquisitions
	Agreement to Purchase Alliant Energy Corporation's Natural Gas Distribution Business in Southeast Minnesota
	In September 2013, MERC entered into an agreement to purchase Alliant Energy Corporation's natural gas distribution business in southeast Minnesota. This transaction is subject to state and federal regulatory approvals. The purchase price will be based on book value as of the closing date, which is expected to approximate $11 million. We anticipate closing on this transaction later in 2014. It will not be material to us.
	Acquisition of Fox Energy Center
	In March 2013, WPS acquired all of the equity interests in Fox Energy Company LLC for $391.6 million. Fox Energy Company LLC was dissolved into WPS immediately after the purchase.
	The purchase included the Fox Energy Center, a 593-megawatt combined-cycle electric generating facility located in Wisconsin, along with associated contracts. Fox Energy Center is a dual-fuel facility, equipped to use fuel oil, but being run primarily on natural gas. This plant gives WPS a more balanced mix of owned electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources. In giving its approval for the purchase, the PSCW stated that the purchase price was reasonable and will benefit ratepayers.
	The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:
	(Millions)
	Assets acquired (1)
	Inventories		$	3
	Other current assets		0.4
	Property, plant, and equipment		374.4
	Other long-term assets (2)		15.6
	Total assets acquired		$	393.4
	Liabilities assumed
	Accounts payable		$	1.8
	Total liabilities assumed		$	1.8
	(1)	Relates to the electric utility segment.
	(2)	Intangible assets recorded for contractual services agreements. See Note 8, Goodwill and Other Intangible Assets, for more information.
	Prior to the purchase, WPS supplied natural gas for the facility and purchased 500 megawatts of capacity and the associated energy output under a tolling arrangement. WPS paid $50.0 million for the early termination of the tolling arrangement. This amount was recorded as a regulatory asset, as WPS is authorized recovery by the PSCW. The amount is being amortized over a nine-year period that began on January 1, 2014.
	WPS received regulatory approval to defer incremental costs incurred in 2013 associated with the purchase of the facility. These costs are included in WPS's 2015 proposed retail electric rate increase. See Note 20, Regulatory Environment, for more information. WPS's rate order effective January 1, 2014, included the costs of operating the Fox Energy Center.
	Pro forma adjustments to our revenues and earnings prior to the date of acquisition would not be meaningful or material. Prior to the acquisition, the Fox Energy Center was a nonregulated plant and sold all of its output to third parties, with most of the output purchased by WPS. The plant is now part of WPS's regulated fleet, used to serve its customers.

DISPOSITIONS

DISPOSITIONS	3 Months Ended
	Mar. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]	'
DISPOSITIONS	'
	Dispositions
	Dispositions at Electric Utility Segment
	Pending Sale of UPPCO
	In January 2014, we reached a definitive agreement to sell all of the stock of UPPCO to Balfour Beatty Infrastructure Partners LP (BBIP) for approximately $298.8 million. This price is subject to adjustments for various items, including working capital, pension contributions, and the reimbursement of any capital expenditures made by UPPCO in 2014 prior to the sale. BBIP approached us in early 2013 about purchasing UPPCO, and we came to an agreement in January 2014 that was approved by our Board of Directors. The transaction is subject to state and federal regulatory approvals and is expected to close later in 2014. Following the sale, IBS will provide certain administrative and operational services to UPPCO during a transition period of 18 to 30 months.
	The pending sale of UPPCO does not meet the requirements under the accounting guidance to qualify as discontinued operations as WPS will have significant continuing cash flows related to certain power purchase transactions that will continue with UPPCO after the sale.
	The following table shows the carrying values of the major classes of assets and liabilities related to UPPCO classified as held for sale on the balance sheets:
	(Millions)	March 31, 2014		31-Dec-13
	Current assets	$	27.2	$	26.5
	Property, plant, and equipment, net of accumulated depreciation of $90.2 and $88.9, respectively	193.2		193.8
	Other long-term assets	65.6		51.6
	Total assets	$	286	$	271.9
	Current liabilities	$	12	$	16.7
	Long-term liabilities	24.7		32.4
	Total liabilities	$	36.7	$	49.1
	In addition to the amounts above, intercompany payables of $2.0 million and $1.6 million at March 31, 2014, and December 31, 2013, respectively, will be included in the sale. These balances were eliminated during consolidation and relate to certain power purchase transactions that will continue with WPS after the sale, as discussed above.
	Discontinued Operations at Holding Company and Other Segment
	During the three months ended March 31, 2013, we recorded $6.0 million of after-tax gains in discontinued operations at the holding company and other segment. In 2013, we remeasured uncertain tax positions included in our liability for unrecognized tax benefits after effectively settling a certain state income tax examination. We reduced the provision for income taxes related to this remeasurement.
	Discontinued Operations at IES Segment
	Potential Sale of Combined Locks Energy Center
	IES is currently pursuing the sale of the Combined Locks Energy Center (Combined Locks), a natural gas-fired co-generation facility located in Wisconsin, as part of its long-term energy asset strategy.
	Combined Locks had $0.7 million of assets that were classified as held for sale on the balance sheets at March 31, 2014, and December 31, 2013, which included inventories and property, plant, and equipment. During each of the three months ended March 31, 2014, and 2013, IES recorded after-tax losses of $0.1 million in discontinued operations related to Combined Locks.
	Sale of WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC
	In March 2013, WPS Empire State, Inc., a subsidiary of IES, sold all of the membership interests of WPS Beaver Falls Generation, LLC (Beaver Falls) and WPS Syracuse Generation, LLC (Syracuse), both of which owned natural gas-fired generation plants located in the state of New York. During the three months ended March 31, 2013, IES recorded after-tax earnings of $0.2 million in discontinued operations related to Beaver Falls and Syracuse.

INVESTMENT_IN_ATC

INVESTMENT IN ATC	3 Months Ended
	Mar. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]	'
INVESTMENT IN ATC	'
	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, 2014. ATC is a for-profit, transmission-only company regulated by FERC.
	The following table shows changes to our investment in ATC:
		Three Months Ended March 31
	(Millions)	2014		2013
	Balance at the beginning of period	$	508.4	$	476.6
	Add: Earnings from equity method investment	22.5		21.7
	Add: Capital contributions	5.1		1.7
	Less: Dividends received	18.4		17.3
	Balance at the end of period	$	517.6	$	482.7
	Financial data for all of ATC is included in the following tables:
		Three Months Ended March 31
	(Millions)	2014		2013
	Income statement data
	Revenues	$	163.3	$	151.8
	Operating expenses	78.6		69.8
	Other expense	21.6		21.5
	Net income	$	63.1	$	60.5
	(Millions)	March 31, 2014		31-Dec-13
	Balance sheet data
	Current assets	$	79.2	$	80.7
	Noncurrent assets	3,563.90		3,509.50
	Total assets	$	3,643.10	$	3,590.20
	Current liabilities	$	301.4	$	381.5
	Long-term debt	1,650.00		1,550.00
	Other noncurrent liabilities	131.2		126.1
	Shareholders’ equity	1,560.50		1,532.60
	Total liabilities and shareholders’ equity	$	3,643.10	$	3,590.20

INVENTORIES

INVENTORIES	3 Months Ended
	Mar. 31, 2014
Inventory Disclosure [Abstract]	'
INVENTORIES	'
	Inventories
	PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the Last-in, First-out (LIFO) cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At March 31, 2014, we had a temporary LIFO liquidation credit of $150.9 million. Due to seasonality requirements, PGL and NSG expect interim reductions in LIFO layers to be replenished by year end.

GOODWILL_AND_OTHER_INTANGIBLE_

GOODWILL AND OTHER INTANGIBLE ASSETS	3 Months Ended
	Mar. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]	'
GOODWILL AND OTHER INTANGIBLE ASSETS	'
	Goodwill and Other Intangible Assets
	We had no changes to the carrying amount of goodwill during the three months ended March 31, 2014, and 2013.
	The identifiable intangible assets other than goodwill listed below are part of other current and long-term assets on the balance sheets. An insignificant amount was recorded as assets held for sale on the balance sheets.
			March 31, 2014							31-Dec-13
	(Millions)		Gross Carrying		Accumulated			Net Carrying		Gross Carrying		Accumulated			Net Carrying
			Amount		Amortization			Amount		Amount		Amortization			Amount
	Amortized intangible assets
	Customer-related (1)		$	26.8	$	(16.1	)	$	10.7	$	26.8	$	(15.7	)	$	11.1
	Contractual service agreements (2)		15.6		(2.4		)	13.2		15.6		(1.8		)	13.8
	Renewable energy credits (3)		9.6		—			9.6		8.4		—			8.4
	Compressed natural gas fueling contract assets (4)		5.6		(2.9		)	2.7		5.6		(2.7		)	2.9
	Customer-owned equipment modifications (5)		4		(0.9		)	3.1		4		(0.9		)	3.1
	Natural gas and electric contract assets (6)		3.9		(1.2		)	2.7		3.9		(0.5		)	3.4
	Nonregulated easements (7)		3.7		(1.2		)	2.5		3.7		(1.1		)	2.6
	Patents/intellectual property (8)		3.4		(0.6		)	2.8		3.4		(0.5		)	2.9
	Other		0.5		(0.3		)	0.2		0.5		(0.3		)	0.2
	Total		$	73.1	$	(25.6	)	$	47.5	$	71.9	$	(23.5	)	$	48.4
	Unamortized intangible assets
	MGU trade name		$	5.2	$	—		$	5.2	$	5.2	$	—		$	5.2
	Trillium trade name (9)		3.5		—			3.5		3.5		—			3.5
	Pinnacle trade name (9)		1.5		—			1.5		1.5		—			1.5
	Total intangible assets		$	83.3	$	(25.6	)	$	57.7	$	82.1	$	(23.5	)	$	58.6
	(1)	Represents customer relationship assets associated with PELLC’s former nonregulated retail natural gas and electric operations, ITF's compressed natural gas fueling operations, and IES's retail natural gas operations. The remaining weighted-average amortization period for customer-related intangible assets at March 31, 2014, was approximately 11 years.
	(2)	Represents contractual service agreements related to maintenance on the combustion turbine generators at the Fox Energy Center. The remaining amortization period for these intangible assets at March 31, 2014, was approximately six years.
	(3)	Used at IES to comply with state Renewable Portfolio Standards and to support customer commitments.
	(4)	Represents the fair value of ITF contracts acquired in September 2011. The remaining amortization period at March 31, 2014, was approximately seven years.
	(5)	Relates to modifications made by IES and ITF to customer-owned equipment. These intangible assets are amortized on a straight-line basis, with a remaining weighted-average amortization period at March 31, 2014, of approximately ten years.
	(6)	Represents the fair value of certain natural gas and electric customer contracts acquired by IES during 2013 that were not considered to be derivative instruments. The remaining amortization period for these intangible assets at March 31, 2014, was approximately four years.
	(7)	Relates to easements supporting a pipeline at IES. The easements are amortized on a straight-line basis, with a remaining amortization period at March 31, 2014, of approximately ten years.
	(8)	Represents the fair value of patents/intellectual property at ITF related to a system for more efficiently compressing natural gas to allow for faster fueling. The remaining amortization period at March 31, 2014, was approximately eight years.
	(9)	Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) are wholly-owned subsidiaries of ITF.
	Amortization expense recorded as a component of nonregulated cost of sales in the statements of income for the three months ended March 31, 2014, and 2013, was $1.0 million and $0.4 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, 2014, and 2013, was $1.1 million and $0.5 million, respectively.
	An insignificant amount of amortization expense was recorded in discontinued operations for the three months ended March 31, 2013.
	The following table shows our estimated amortization expense for the next five years, including amounts recorded through March 31, 2014:
			For the Year Ending December 31
	(Millions)		2014		2015			2016		2017		2018
	Amortization to be recorded in nonregulated cost of sales		$	3.4	$	2		$	1.1	$	0.9	$	0.8
	Amortization to be recorded in depreciation and amortization expense		4.3		4.2			4		3.9		3.8

SHORTTERM_DEBT_AND_LINES_OF_CR

SHORT-TERM DEBT AND LINES OF CREDIT	3 Months Ended
	Mar. 31, 2014
Short-term Debt [Abstract]	'
SHORT-TERM DEBT AND LINES OF CREDIT	'
	Short-Term Debt and Lines of Credit
	Our outstanding short-term borrowings were as follows:
	(Millions, except percentages)	March 31, 2014				31-Dec-13
	Commercial paper	$	321.9			$	326
	Average interest rate on commercial paper	0.23		%		0.22		%
	The commercial paper outstanding at March 31, 2014, had maturity dates ranging from April 1, 2014, through May 5, 2014.
	Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2014, and 2013, was $247.1 million and $400.7 million, respectively.
	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 as of March 31:
	(Millions)	Maturity		March 31, 2014				31-Dec-13
	Revolving credit facility (Integrys Energy Group)	5/17/14		$	275			$	275
	Revolving credit facility (Integrys Energy Group)	5/17/16		200				200
	Revolving credit facility (Integrys Energy Group)	6/13/17		635				635
	Revolving credit facility (WPS)	5/17/14		135				135
	Revolving credit facility (WPS)	6/13/17		115				115
	Revolving credit facility (PGL)	6/13/17		250				250
	Total short-term credit capacity			$	1,610.00			$	1,610.00
	Less:
	Letters of credit issued inside credit facilities			$	70.6			$	52.4
	Commercial paper outstanding			321.9				326
	Available capacity under existing agreements			$	1,217.50			$	1,231.60

INCOME_TAXES

INCOME TAXES	3 Months Ended
	Mar. 31, 2014
Income Tax Disclosure [Abstract]	'
INCOME TAXES	'
	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 attributable to continuing operations:
		Three Months Ended March 31
		2014		2013
	Effective tax rate	37	%	37.6	%
	Our effective tax rate normally differs from the federal statutory tax rate of 35% due to additional provision for multistate income tax obligations. No other items had a significant impact on our effective tax rates during the three months ended March 31, 2014, and 2013.
	During the three months ended March 31, 2014, there was not a significant change in our liability for unrecognized tax benefits.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	3 Months Ended
	Mar. 31, 2014
Commitments and Contingencies Disclosure [Abstract]	'
COMMITMENTS AND CONTINGENCIES	'
	Commitments and Contingencies
	(a) Unconditional Purchase Obligations and Purchase Order Commitments
	We and our subsidiaries routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. The regulated natural gas utilities have obligations to distribute and sell natural gas to their customers, and the regulated electric utilities have obligations to distribute and sell electricity to their customers. The utilities expect to recover costs related to these obligations in future customer rates. Additionally, the majority of the energy supply contracts entered into by IES are to meet its contractual obligations to deliver energy to customers. The following table shows our minimum future commitments related to these purchase obligations as of March 31, 2014, including those of our subsidiaries.
						Payments Due By Period
	(Millions)		Year Contracts Extend Through	Total Amounts Committed		2014		2015		2016		2017		2018		Later Years
	Natural gas utility supply and transportation		2028	$	793.7	$	128.2	$	169.7	$	158.5	$	122.6	$	71.7	$	143
	Electric utility
	Purchased power *		2029	918		59.8		49.4		42.8		53.2		54		658.8
	Coal supply and transportation		2018	94.6		47		28.5		9.9		5.9		3.3		—
	Nonregulated electricity and natural gas supply		2020	600.9		376.4		161.2		51.9		9.4		1.6		0.4
	Total			$	2,407.20	$	611.4	$	408.8	$	263.1	$	191.1	$	130.6	$	802.2
	*	Includes minimum future commitments for UPPCO related to power purchase contracts of $8.2 million for the years 2014 to 2024. In January 2014, we announced an agreement to sell UPPCO. See Note 5, Dispositions, for more information.
	We and our subsidiaries also had commitments of $1,163.3 million in the form of purchase orders issued to various vendors at March 31, 2014, that relate to normal business operations, including construction projects. Included in this amount are purchase orders issued to various vendors of UPPCO for $12.2 million.
	(b) Environmental Matters
	Air Permitting Violation Claims
	Weston and Pulliam Clean Air Act (CAA) Issues:
	In November 2009, the EPA issued a Notice of Violation (NOV) to WPS alleging violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. WPS reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree. This Consent Decree was approved by the U.S. District Court (Court) in March 2013, after a public comment period. The final Consent Decree includes:
	•	the installation of emission control technology, including ReACT™, on Weston 3,
	•	changed operating conditions (including refueling, repowering, and/or retirement of units),
	•	limitations on plant emissions,
	•	beneficial environmental projects totaling $6.0 million (various options, including capital projects, are available), and
	•	a civil penalty of $1.2 million.
	As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. The early retirement of certain Weston and Pulliam units mentioned in the Consent Decree has been announced.
	WPS received approval from the PSCW in its 2014 rate order to recover prudently incurred 2014 costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. We also believe that prudently incurred costs after 2014 will be recoverable from customers based on past precedent with the PSCW.
	In May 2010, WPS received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of March 31, 2014. It is unknown whether the Sierra Club will take further action in the future.
	Columbia and Edgewater CAA Issues:
	In December 2009, the EPA issued an NOV to Wisconsin Power and Light (WP&L), the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric and WPS. The NOV alleges violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, WP&L, and Madison Gas and Electric (Joint Owners) reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree. This Consent Decree was approved by the Court in June 2013, after a public comment period. The final Consent Decree includes:
	•	the installation of emission control technology, including scrubbers at the Columbia plant,
	•	changed operating conditions (including refueling, repowering, and/or retirement of units),
	•	limitations on plant emissions,
	•	beneficial environmental projects, with WPS's portion totaling $1.3 million (various options, including capital projects, are available), and
	•	WPS's portion of a civil penalty and legal fees totaling $0.4 million.
	As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain of the Columbia and Edgewater units. As of March 31, 2014, no decision had been made on how to address this requirement. Therefore, retirement of the Columbia and Edgewater units mentioned in the Consent Decree was not considered probable.
	We believe that significant costs prudently incurred as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty, will be recoverable from customers.
	Weston Title V Air Permit:
	In July 2013, the WDNR issued the Weston Title V air permit. In September 2013, WPS challenged various requirements in the permit by filing a contested case proceeding with the WDNR and also filed a Petition for Judicial Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also filed Petitions for Judicial Review and requests for contested case proceedings regarding various aspects of the permit. The WDNR granted all parties' requests for contested case proceedings. WPS has filed permit amendment applications such that, if the facility permits and the Title V air permit are amended in accordance with the applications, several of the issues WPS raised would be resolved. The contested case petitions have not yet been referred to an Administrative Law Judge. The Petitions for Judicial Review, by all parties, have been stayed pending the resolution of the contested cases.
	Mercury and Interstate Air Quality Rules
	Mercury:
	The State of Wisconsin's mercury rule requires a 40% reduction from historical baseline mercury emissions, beginning January 1, 2010, through the end of 2014. Beginning in 2015, electric generating units above 150 megawatts will be required to reduce mercury emissions by 90% from the historical baseline. Reductions can be phased in and the 90% target delayed until 2021 if additional sulfur dioxide and nitrogen oxide reductions are implemented. By 2015, electric generating units above 25 megawatts, but less than 150 megawatts, must reduce their mercury emissions to a level defined by the Best Available Control Technology rule. As of March 31, 2014, WPS estimated capital costs of approximately $8 million for its wholly owned plants to achieve the required reductions. The capital costs are expected to be recovered in future rates.
	In December 2011, the EPA issued the final Utility Mercury and Air Toxics Standards (MATS), which will regulate emissions of mercury and other hazardous air pollutants beginning in 2015. The State of Wisconsin is in the process of revising the state mercury rule to be consistent with the MATS rule. Projects approved and initiated to address the State of Wisconsin mercury rule are expected to ensure compliance with the mercury limits in the MATS rule.
	Sulfur Dioxide and Nitrogen Oxide:
	In July 2011, the EPA issued a final rule known as the Cross State Air Pollution Rule (CSAPR), which numerous parties, including WPS, challenged in the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). The new rule was to become effective in January 2012. However, in December 2011, the CSAPR requirements were stayed by the D.C. Circuit and a previous rule, the Clean Air Interstate Rule (CAIR), was implemented during the stay period. In August 2012, the D.C. Circuit issued their ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. The case was appealed to the United States Supreme Court, and on April 29, 2014, the Supreme Court upheld the CSAPR rule and remanded the case to the Court of Appeals for the D.C. Circuit. There are remaining issues before the D.C. Circuit, and there will need to be additional rulemakings before CSAPR is implemented. As a result, it is premature to speculate on what additional controls or other actions, if any, we may be required to implement. WPS expects to recover any future compliance costs in future rates. The potential impact on IES is not expected to be material.
	The stay of CSAPR is still in effect. Under CAIR, units affected by the Best Available Retrofit Technology (BART) rule were considered in compliance with BART for sulfur dioxide and nitrogen oxide emissions if they were in compliance with CAIR. This determination was updated when CSAPR was issued (CSAPR satisfied BART), and the EPA has not revised it to reflect the reinstatement of CAIR. Although particulate emissions also contribute to visibility impairment, the WDNR's modeling has shown the impairment to be so insignificant that additional capital expenditures on controls may not be warranted.
	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. The natural gas utilities are coordinating the investigation and cleanup of the sites subject to EPA jurisdiction under what is called a "multisite" 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. Our balance sheets include liabilities of $588.2 million that we have estimated and accrued for as of March 31, 2014, for 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, 2014, cash expenditures for environmental remediation not yet recovered in rates were $34.1 million. Our balance sheets also include a regulatory asset of $622.3 million at March 31, 2014, which is net of insurance recoveries, related to the expected recovery through rates of both cash expenditures and estimated future expenditures.
	Management believes that any costs incurred for environmental activities relating to former manufactured gas plant operations that are not recoverable through contributions from other entities or from insurance carriers have been prudently incurred and are, therefore, recoverable through rates for MGU, NSG, PGL, and WPS. Accordingly, we do not expect these costs to have a material impact on our financial statements. However, any changes in the approved rate mechanisms for recovery of these costs, or any adverse conclusions by the various regulatory commissions with respect to the prudence of costs actually incurred, could materially affect recovery of such costs through rates.

GUARANTEES

GUARANTEES	3 Months Ended
	Mar. 31, 2014
Guarantees [Abstract]	'
GUARANTEES	'
	Guarantees
	The following table shows our outstanding guarantees:
			Total Amounts Committed		Expiration
	(Millions)		at March 31, 2014		Less Than 1 Year		1 to 3 Years		Over 3 Years
	Guarantees supporting commodity transactions of subsidiaries (1) (5)		$	684.5	$	412.6	$	31.7	$	240.2
	Standby letters of credit (2) (5)		74.1		70.7		3.3		0.1
	Surety bonds (3)		29.1		29.1		—		—
	Other guarantees (4) (5)		55.3		1.5		—		53.8
	Total guarantees		$	843	$	513.9	$	35	$	294.1
	(1)	Consists of (a) $497.7 million, $5.0 million, and $2.0 million to support the business operations of IES, IBS, and UPPCO, respectively, and (b) $126.7 million, $52.9 million, and $0.2 million related to natural gas supply at MERC, MGU and ITF, respectively. 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 $72.1 million issued to support IES’s operations and $2.0 million issued to support ITF, MERC, MGU, NSG, PGL, UPPCO, and WPS. These amounts are not reflected on our balance sheets.
	(3)	Primarily for the construction and operation of compressed natural gas fueling stations, 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) $35.0 million to support IES's future payment obligations related to its distributed solar generation projects. This guarantee is not reflected on our balance sheets; (b) $10.0 million related to the sale agreement for IES's 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 law; (c) $1.8 million related to the sale of WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC. IES's guaranteed the buyer's performance under certain derivative contracts that the buyer assumed from WPS Empire State, Inc. in conjunction with the sale; (d) $2.4 million related to the performance of an operating and maintenance agreement by ITF; and (e) $6.1 million related to other indemnifications primarily for workers compensation coverage. The amounts discussed in items (c) through (e) above are not reflected on our balance sheets.
	(5)	Consists of $3.4 million of guarantees related to UPPCO. See Note 5, Dispositions, for more information on the pending sale of UPPCO.

EMPLOYEE_BENEFIT_PLANS

EMPLOYEE BENEFIT PLANS	3 Months Ended
	Mar. 31, 2014
Compensation and Retirement Disclosure [Abstract]	'
EMPLOYEE BENEFIT PLANS	'
	Employee Benefit Plans
	The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans:
		Pension Benefits						Other Postretirement Benefits
		Three Months Ended March 31						Three Months Ended March 31
	(Millions)	2014			2013			2014			2013
	Service cost	$	6.6		$	7.5		$	5.9		$	6.5
	Interest cost	19.7			17.8			7.1			6.3
	Expected return on plan assets	(28.9		)	(26.6		)	(8.8		)	(7.7		)
	Amortization of prior service cost (credit)	0.2			1			(1.3		)	(0.6		)
	Amortization of net actuarial loss	8.4			13.5			0.7			2
	Net periodic benefit cost	$	6		$	13.2		$	3.6		$	6.5
	Prior service costs (credits) and net actuarial losses that have not yet been recognized as a component of net periodic benefit cost are recorded in accumulated other comprehensive income for our nonregulated entities and as net regulatory assets or liabilities for our regulated utilities.
	On March 1, 2014, we remeasured the obligations of certain other postretirement benefit plans. The remeasurement was necessary because we will replace the current retiree medical plans for participants age 65 and older with a Medicare Advantage plan starting in 2015.
	Our funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. During the three months ended March 31, 2014, we contributed $68.6 million to our pension plans. Amounts contributed to our other postretirement benefit plans were not significant. We expect to contribute an additional $3.7 million to our pension plans and $11.8 million to our other postretirement benefit plans during the remainder of 2014, dependent upon various factors affecting us, including our liquidity position and tax law changes.

STOCKBASED_COMPENSATION

STOCK-BASED COMPENSATION	3 Months Ended
	Mar. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
STOCK-BASED COMPENSATION	'
	Stock-Based Compensation
	The following table reflects the stock-based compensation expense and the related deferred income tax benefit recognized in income for the three months ended March 31:
	(Millions)		2014			2013
	Stock options		$	0.3		$	0.4
	Performance stock rights		0.5			2.2
	Restricted share units		3.1			2.8
	Nonemployee director deferred stock units		0.2			0.3
	Total stock-based compensation expense		$	4.1		$	5.7
	Deferred income tax benefit		$	1.6		$	2.3
	No stock-based compensation cost was capitalized during the three months ended March 31, 2014, and 2013.
	Stock Options
	The fair value of stock option awards granted is estimated using a binomial lattice model. The expected term of option awards is derived from the output of the binomial lattice model 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. The expected stock price volatility is estimated using the 10-year historical volatility of our stock price. The following table shows the assumptions incorporated into the valuation model:
			February 2014 Grant
	Expected term		8 years
	Risk-free interest rate		0.12% – 2.88%
	Expected dividend yield		5.28%
	Expected volatility		18%
	The weighted-average fair value per stock option granted during the three months ended March 31, 2014, and 2013, was $6.70 and $6.03, respectively.
	A summary of stock option activity for the three months ended March 31, 2014, and information related to outstanding and exercisable stock options at March 31, 2014, is presented below:
			Stock Options		Weighted-Average			Weighted-Average	Aggregate
					Exercise Price Per			Remaining	Intrinsic Value
					Share			Contractual Life	(Millions)
								(in Years)
	Outstanding at December 31, 2013		1,550,374		$	50.93
	Granted		264,332		55.23
	Exercised		(11,504	)	45.45
	Outstanding at March 31, 2014		1,803,202		$	51.6		6.6	$	14.5
	Exercisable at March 31, 2014		1,114,027		$	49.75		5.1	$	11
	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 on March 31, 2014. This is calculated as the difference between our closing stock price on March 31, 2014, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised was not significant during the three months ended March 31, 2014, and was $1.9 million during the three months ended March 31, 2013. The actual tax benefit realized for the tax deductions from these option exercises was not significant during the three months ended March 31, 2014, and 2013.
	As of March 31, 2014, $2.5 million of compensation cost related to unvested and outstanding stock options was expected to be recognized over a weighted-average period of 2.0 years.
	Performance Stock Rights
	The fair values of performance stock rights are estimated using a Monte Carlo valuation model. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. The expected stock price volatility is estimated using two to three years of historical data. The table below reflects the assumptions used in the valuation of the outstanding grants at March 31:
			2014
	Risk-free interest rate		0.34% – 0.57%
	Expected dividend yield		5.28% – 5.33%
	Expected volatility		15% – 22%
	A summary of the activity for the three months ended March 31, 2014, related to performance stock rights accounted for as equity awards is presented below:
			Performance		Weighted-Average
			Stock Rights		Fair Value *
	Outstanding at December 31, 2013		85,749		$	46.62
	Granted		21,146		44.28
	Adjustment for shares not distributed		(45,748	)	43.29
	Outstanding at March 31, 2014		61,147		$	48.31
	*	Reflects the weighted-average fair value used to measure equity awards. Equity awards are measured using the grant date fair value or the fair value on the modification date.
	The weighted-average grant date fair value of performance stock rights awarded during the three months ended March 31, 2014, and 2013, was $44.28 and $48.50, per performance stock right, respectively.
	A summary of the activity for the three months ended March 31, 2014, related to performance stock rights accounted for as liability awards is presented below:
			Performance
			Stock Rights
	Outstanding at December 31, 2013		198,904
	Granted		84,529
	Adjustment for shares not distributed		(39,001	)
	Outstanding at March 31, 2014		244,432
	The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of March 31, 2014, was $38.73 per performance stock right.
	No shares of common stock were distributed for performance stock rights during the three months ended March 31, 2014, because the performance percentage was below the threshold payout level for those rights that were eligible for distribution. The total intrinsic value of shares distributed during the three months ended March 31, 2013, was $8.8 million. The actual tax benefit realized for the tax deductions from the distribution of shares during the three months ended March 31, 2013, was $3.6 million.
	As of March 31, 2014, $5.2 million of compensation cost related to unvested and outstanding performance stock rights (equity and liability awards) was expected to be recognized over a weighted-average period of 1.6 years.
	Restricted Share Units
	A summary of the activity related to all restricted share unit awards (equity and liability awards) for the three months ended March 31, 2014, is presented below:
			Restricted Share		Weighted-Average Grant Date Fair Value
			Unit Awards
	Outstanding at December 31, 2013		511,301		$	52.24
	Granted		214,953		55.23
	Dividend equivalents		6,169		54.45
	Vested and released		(204,322	)	49.73
Forfeited		(781	)	54.42
Outstanding at March 31, 2014		527,320		$	54.45
The weighted-average grant date fair value of restricted share units awarded during the three months ended March 31, 2014, and 2013, was $55.23 and $56.00 per unit, respectively.
The total intrinsic value of restricted share unit awards vested and released during the three months ended March 31, 2014, and 2013, was $11.1 million and $11.4 million, respectively. The actual tax benefit realized for the tax deductions from the vesting and release of restricted share units during the three months ended March 31, 2014, and 2013, was $4.4 million and $4.6 million respectively.
As of March 31, 2014, $18.7 million of compensation cost related to unvested and outstanding restricted share units was expected to be recognized over a weighted-average period of 2.5 years.
Nonemployee Directors Deferred Stock Units
Each nonemployee director is granted deferred stock units (DSUs), typically in January of each year. These awards generally vest over one year; therefore, the expense is recognized pro-rata over the year in which the grant occurs. The number of DSUs granted is calculated by dividing a set dollar amount by our closing common stock price on December 31 of the prior year. Nonemployee directors also receive forfeitable dividend equivalents in the form of additional DSU's.

COMMON_EQUITY

COMMON EQUITY	3 Months Ended
	Mar. 31, 2014
Stockholders' Equity Note [Abstract]	'
COMMON EQUITY	'
	Common Equity
	We had the following changes to issued common stock during the three months ended March 31, 2014:
	Balance at December 31, 2013		79,919,176
	Shares issued
	Employee Stock Ownership Plan		31,764
	Stock Investment Plan		12,151
	Balance at March 31, 2014		79,963,091
	The following table provides a summary of common stock activity to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans:
	Period		Method of meeting requirements
	Beginning 02/05/14		Purchasing shares on the open market
	02/05/2013 – 02/04/2014		Issued new shares
	01/01/2013 – 02/04/2013		Purchased shares on the open market
	The following table reconciles common shares issued and outstanding:
			March 31, 2014							December 31, 2013
			Shares			Average Cost *				Shares			Average Cost *
	Common stock issued		79,963,091							79,919,176
	Less:
	Deferred compensation rabbi trust		428,720			$	48.6			473,796			$	48.5
	Total common shares outstanding		79,534,371							79,445,380
	*	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. As the obligation for the shares issuable under the deferred compensation plan is accounted for as a liability, the numerator is adjusted for any changes in income or loss that would have resulted had it been accounted for as an equity instrument during the period.
	The following table reconciles our computation of basic and diluted earnings per share:
			Three Months Ended March 31
	(Millions, except per share amounts)		2014				2013
	Numerator:
	Net income from continuing operations		$	153.2			$	182.2
	Discontinued operations, net of tax		(0.1		)		6.1
	Preferred stock dividends of subsidiary		(0.8		)		(0.8		)
	Noncontrolling interest in subsidiaries		0.1				—
	Net income attributed to common shareholders		$	152.4			$	187.5
	Denominator:
	Average shares of common stock — basic		80.2				78.7
	Effect of dilutive securities
	Stock-based compensation		0.3				0.4
	Deferred compensation		—				0.2
	Average shares of common stock — diluted		80.5				79.3
	Earnings per common share
	Basic		$	1.9			$	2.38
	Diluted		1.89				2.37
	The calculation of diluted earnings per share excluded the following weighted-average outstanding securities that had an anti-dilutive effect:
			Three Months Ended March 31
	(Millions)		2014			2013
	Stock-based compensation		0.7			0.2
	Deferred compensation		0.3			—
	Dividend Restrictions
	Our ability as a holding company to pay dividends is largely dependent upon the availability of funds from our subsidiaries. Various laws, regulations, and financial covenants impose restrictions on the ability of certain of our regulated utility subsidiaries to transfer funds to us in the form of dividends. Our regulated utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly.
	The PSCW allows WPS to pay dividends on its common stock of no more than 103% of the previous year’s common stock dividend. WPS may return capital to us if its average financial common equity ratio is at least 51% on a calendar-year basis. WPS must obtain PSCW approval if a return of capital would cause its average financial common equity ratio to fall below this level. Our right to receive dividends on the common stock of WPS is also subject to the prior rights of WPS’s preferred shareholders and to provisions in WPS’s restated articles of incorporation, which limit the amount of common stock dividends that WPS may pay if its common stock and common stock surplus accounts constitute less than 25% of its total capitalization.
	NSG’s long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock.
	PGL and WPS have short-term debt obligations containing financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of their outstanding debt obligations.
	We also have short-term and long-term debt obligations that contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of outstanding debt obligations. At March 31, 2014, these covenants restricted the payment of any dividends beyond the amount allowed under our subsidiary requirements described above.
	As of March 31, 2014, total restricted net assets were $1,846.5 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $146.8 million at March 31, 2014.
	We have the option to defer interest payments on our outstanding Junior Subordinated Notes, from time to time, for one or more periods of up to ten consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, purchase, acquire, or make a liquidation payment on, any of our capital stock.
	Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.
	Capital Transactions with Subsidiaries
	During the three months ended March 31, 2014, capital transactions with subsidiaries were as follows (in millions):
	Subsidiary		Dividends To Parent				Return Of				Equity Contributions
							Capital To Parent				From Parent
	IBS		$	—			$	—			$	15
	ITF (1)		—				—				17.4
	MERC		—				18				—
	MGU		—				7				—
	UPPCO		—				3.5				—
WPS		28				—				—
WPS Investments, LLC (2)		18.3				—				5.1
Total		$	46.3			$	28.5			$	37.5
(1)	ITF is a direct wholly owned subsidiary of PELLC. As a result, it makes distributions to PELLC, and receives equity contributions from PELLC. Subject to applicable law, PELLC does not have any dividend restrictions or limitations on distributions to us.
(2)	WPS Investments, LLC is a consolidated subsidiary that is jointly owned by us, WPS, and UPPCO. At March 31, 2014, we had an 86.37% ownership interest, while WPS and UPPCO had an 11.24% and 2.39% ownership interest, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2014, all equity contributions to WPS Investments, LLC were made solely by us.

ACCUMULATED_OTHER_COMPREHENSIV

ACCUMULATED OTHER COMPREHENSIVE LOSS	3 Months Ended
	Mar. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]	'
ACCUMULATED OTHER COMPREHENSIVE LOSS	'
	Accumulated Other Comprehensive Loss
	The following tables show the changes, net of tax, to our accumulated other comprehensive loss during the three months ended March 31:
	Three Months Ended March 31, 2014								Accumulated Other
	(Millions)		Cash Flow Hedges			Defined Benefit Plans			Comprehensive Loss
	Beginning balance at December 31, 2013		$	(3.1	)	$	(20.1	)	$	(23.2	)
	Other comprehensive loss before reclassifications		—			(0.1		)	(0.1		)
	Amounts reclassified out of accumulated other comprehensive loss		(0.6		)	0.3			(0.3		)
	Net current period other comprehensive income (loss)		(0.6		)	0.2			(0.4		)
	Ending balance at March 31, 2014		$	(3.7	)	$	(19.9	)	$	(23.6	)
	Three Months Ended March 31, 2013								Accumulated Other
	(Millions)		Cash Flow Hedges			Defined Benefit Plans			Comprehensive Loss
	Beginning balance at December 31, 2012		$	(5.2	)	$	(35.7	)	$	(40.9	)
	Other comprehensive income before reclassifications		0.1			—			0.1
	Amounts reclassified out of accumulated other comprehensive loss		0.9			0.6			1.5
	Net current period other comprehensive income		1			0.6			1.6
	Ending balance at March 31, 2013		$	(4.2	)	$	(35.1	)	$	(39.3	)
	The following table shows the reclassifications out of accumulated other comprehensive loss during the three months ended March 31:
			Amount Reclassified
			Three Months Ended March 31
	(Millions)		2014			2013			Affected Line Item in the Statements of Income
	Losses on cash flow hedges
	Utility commodity derivative contracts		$	—		$	0.2		Operating and maintenance expense (1) (2)
	Nonregulated commodity derivative contracts		—			1.1			Nonregulated revenues (2)
	Interest rate hedges		0.3			0.2			Interest expense
			0.3			1.5			Total before tax
			0.9			0.6			Tax expense
			(0.6		)	0.9			Net of tax
	Defined benefit plans
	Amortization of prior service credits		(0.1		)	(0.1		)	(3)
	Amortization of net actuarial losses		0.7			1.1			(3)
			0.6			1			Total before tax
			0.3			0.4			Tax expense
			0.3			0.6			Net of tax
	Total reclassifications		$	(0.3	)	$	1.5
	(1)	This item relates to changes in the price of natural gas used to support utility operations.
	(2)	We no longer designate commodity contracts as cash flow hedges.
	(3)	These items are included in the computation of net periodic benefit cost. See Note 13, Employee Benefit Plans, for more information.

VARIABLE_INTEREST_ENTITIES

VARIABLE INTEREST ENTITIES	3 Months Ended
	Mar. 31, 2014
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract]	'
VARIABLE INTEREST ENTITIES	'
	Variable Interest Entities
	Consolidated Variable Interest Entities
	In 2012, ITF formed AMP Trillium LLC as a joint venture with AMP Americas LLC. ITF owns 30% and AMP Americas LLC owns 70% of the joint venture. The joint venture was established to own and operate compressed natural gas fueling stations. The preferred source of capital funding for the joint venture is loans from ITF. We determined that the joint venture is a variable interest entity and that ITF was the primary beneficiary, which required us to consolidate the assets, liabilities, and statements of income of the joint venture. At March 31, 2014, and December 31, 2013, our variable interests in the joint venture included an insignificant equity investment and insignificant receivables. Our maximum exposure to loss as a result of this joint venture was not significant. The carrying amounts of AMP Trillium LLC assets and liabilities included on our balance sheets were also not significant.
	In April 2014, ITF and AMP Americas LLC restructured this joint venture. As a result of the restructuring, our influence over the activities that most significantly impact the variable interest entity's economic performance decreased. We have determined that ITF is no longer the primary beneficiary of this variable interest entity and that we are no longer required to consolidate the joint venture. Therefore, we started accounting for this variable interest entity as an equity method investment in April 2014.
	Unconsolidated Variable Interest Entities
	In 2013, ITF formed EVO Trillium LLC as a joint venture with Environmental Alternative Fuels LLC. ITF owns 15% and Environmental Alternative Fuels LLC owns 85% of the joint venture. This joint venture was established to own and operate compressed natural gas fueling stations. We determined that this joint venture is a variable interest entity but that consolidation is not required since we are not its primary beneficiary, as we do not have the power to direct its activities. We instead account for this variable interest entity as an equity method investment. At March 31, 2014, and December 31, 2013, the assets and liabilities on our balance sheets related to our involvement with this variable interest entity consisted of insignificant receivables. Our maximum exposure to loss as a result of involvement with this variable interest entity was also not significant.
	We have a variable interest in an entity through a power purchase agreement at UPPCO that reimburses an independent power producing entity for coal costs relating to purchased energy. There is no obligation to purchase energy under this agreement. This contract for 17.5 megawatts of capacity expires in December 2014. For a variety of reasons, including qualitative factors such as the length of the remaining term of the contract compared with the remaining life of the plant and the fact that we do not have the power to direct the operations and maintenance of the facility, we determined we are not the primary beneficiary of this variable interest entity and that consolidation is not required. At March 31, 2014, and December 31, 2013, the assets and liabilities on our balance sheets that related to our involvement with this variable interest entity pertained to working capital accounts and represented the amounts we owed for current deliveries of power. We have not guaranteed any debt or provided any equity support, liquidity arrangements, performance guarantees, or other commitments associated with the contract. Our maximum exposure to loss as a result of involvement with this variable interest entity was not significant.

FAIR_VALUE

FAIR VALUE	3 Months Ended
	Mar. 31, 2014
Fair Value Disclosures [Abstract]	'
FAIR VALUE	'
	Fair Value
	Fair Value Measurements
	A fair value measurement is required to reflect the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model.
	Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities.
	Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:
	Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
	Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.
	Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.
	Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
	We primarily determine fair value using a market-based approach that uses observable market inputs where available, and internally developed inputs only when 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), and price correlation (for cross commodity contracts). These inputs are available through multiple sources, including exchanges and brokers. 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 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 department 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. Changes to the fair value inputs are made if necessary.
	We conduct a thorough review of fair value hierarchy classifications on a quarterly basis.
	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, 2014
	(Millions)		Level 1			Level 2			Level 3			Total
	Assets
	Risk Management Assets
	Utility Segments
	Natural gas contracts		$	0.9		$	12.4		$	—		$	13.3
	Financial transmission rights (FTRs)		—			—			0.9			0.9
	Petroleum product contracts		0.1			—			—			0.1
	Coal contracts		—			—			1.8			1.8
	Nonregulated Segments
	Natural gas contracts		20.6			28.8			27.5			76.9
	Electric contracts		88			127.6			21.8			237.4
	Total Risk Management Assets		$	109.6		$	168.8		$	52		$	330.4
	Investment in exchange-traded funds		$	16.2		$	—		$	—		$	16.2
	Liabilities
	Risk Management Liabilities
	Utility Segments
	Natural gas contracts		$	0.2		$	0.2		$	—		$	0.4
	FTRs		—			—			0.2			0.2
	Coal contracts		—			—			1.5			1.5
	Nonregulated Segments
	Natural gas contracts		10.2			20.4			22			52.6
	Electric contracts		112.3			51.9			3.1			167.3
	Total Risk Management Liabilities		$	122.7		$	72.5		$	26.8		$	222
	Contingent consideration related to the acquisition of Compass Energy Services (Compass)		$	—		$	—		$	7.8		$	7.8
			31-Dec-13
	(Millions)		Level 1			Level 2			Level 3			Total
	Assets
	Risk Management Assets
	Utility Segments
	Natural gas contracts		$	2.4		$	7.7		$	—		$	10.1
	FTRs		—			—			2.1			2.1
	Petroleum product contracts		0.1			—			—			0.1
	Coal contracts		—			—			0.2			0.2
	Nonregulated Segments
	Natural gas contracts		16.3			35.2			35.6			87.1
	Electric contracts		65.1			134.9			15.9			215.9
	Total Risk Management Assets		$	83.9		$	177.8		$	53.8		$	315.5
	Investment in exchange-traded funds		$	15.9		$	—		$	—		$	15.9
	Liabilities
	Risk Management Liabilities
	Utility Segments
	Natural gas contracts		$	0.5		$	0.6		$	—		$	1.1
	FTRs		—			—			0.3			0.3
	Coal contracts		—			—			2.7			2.7
	Nonregulated Segments
Natural gas contracts		14.3			22			25.2			61.5
Electric contracts		98.8			58.7			3.5			161
Total Risk Management Liabilities		$	113.6		$	81.3		$	31.7		$	226.6
Contingent consideration related to the acquisition of Compass		$	—		$	—		$	7.8		$	7.8
The risk management assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO market. See Note 3, Risk Management Activities, for more information.
The following tables show net risk management assets transferred between the levels of the fair value hierarchy:
		Nonregulated Segments — Natural Gas Contracts
		Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
(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			—
Transfers into Level 3 from		—			0.9			N/A			—			0.2			N/A
		Nonregulated Segments — Electric Contracts
		Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
(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			4.4			$	—		N/A			5.5
Transfers into Level 3 from		—			2.6			N/A			—			—			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 at the value as of the end of the reporting period.
The amounts and percentages listed in the table below represent the range of unobservable inputs used in the valuations that individually had a significant impact on the fair value determination and caused a derivative to be classified as Level 3 at March 31, 2014:
		Fair Value (Millions)
		Assets			Liabilities			Valuation Technique		Unobservable Input	Average or Range
Utility Segments
FTRs		$	0.9		$	0.2		Market-based		Forward market prices ($/megawatt-month) (1)	$172.92
Coal contracts		1.8			1.5			Market-based		Forward market prices ($/ton) (2)	$12.11 — $15.25
Nonregulated Segments
Natural gas contracts		27.5			22			Market-based		Forward market prices ($/dekatherm) (3)	($2.59) — $3.85
										Probability of default (4)	11.6% — 51.0%
Electric contracts		21.8			3.1			Market-based		Forward market prices ($/megawatt-hours) (3)	($5.02) — $10.06
										Probability of default (4)	26.00%
										Option volatilities (5)	19.8% — 155.6%
										Monthly curve shaping (6)	-27.00%
Contingent consideration related to the acquisition of Compass		N/A			7.8			Income-based		Growth rate (7)	(13.2)% - 49.3%
(1)	Represents forward market prices developed using historical cleared pricing data from MISO.
(2)	Represents third-party forward market pricing.
(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)	Based on Moody's one-year counterparty default percentages.
(5)	Represents the range of volatilities used in the valuation of options. Volatilities are derived from an internal model using volatility curves from third parties.
(6)	Represents adjustments made to forward market price curves to disaggregate average prices of multiple periods into discrete monthly prices.
(7)	Represents the range of assumed growth rates of earnings before interest, taxes, and amortization input into the valuation model.
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. A significant decrease in the growth rate used to value the contingent consideration would result in a directionally similar significant change in fair value. A significant increase in the growth rate would not have a significant impact on the fair value as the contingent consideration is limited to $8.0 million.
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, 2014		Nonregulated Segments									Utility Segments
(Millions)		Natural Gas			Electric			Contingent Consideration			FTRs			Coal Contracts			Total
Balance at the beginning of the period		$	10.4		$	12.4		$	(7.8	)	$	1.8		$	(2.5	)	$	14.3
Net realized and unrealized (losses) gains included in earnings		(6.2		)	12.6			—			0.4			—			6.8
Net unrealized gains recorded as regulatory assets or liabilities		—			—			—			—			2.2			2.2
Purchases		—			0.7			—			(0.1		)	—			0.6
Sales		—			(0.7		)	—			—			—			(0.7		)
Settlements		0.5			(4.5		)	—			(1.4		)	0.6			(4.8		)
Net transfers into Level 3		0.9			2.6			—			—			—			3.5
Net transfers out of Level 3		(0.1		)	(4.4		)	—			—			—			(4.5		)
Balance at the end of the period		$	5.5		$	18.7		$	(7.8	)	$	0.7		$	0.3		$	17.4
Net unrealized (losses) gains included in earnings related to instruments still held at the end of the period		$	(6.2	)	$	12.6		$	—		$	—		$	—		$	6.4
Three Months Ended March 31, 2013		Nonregulated Segments						Utility Segments
(Millions)		Natural Gas			Electric			FTRs			Coal Contracts			Total
Balance at the beginning of the period		$	3.9		$	(4.3	)	$	2		$	(6.5	)	$	(4.9	)
Net realized and unrealized (losses) gains included in earnings		(1.5		)	15.1			0.3			—			13.9
Net unrealized (losses) gains recorded as regulatory assets or liabilities		—			—			(0.2		)	3.1			2.9
Purchases		—			0.7			—			—			0.7
Settlements		(0.9		)	0.1			(1.2		)	(1.2		)	(3.2		)
Net transfers into Level 3		0.2			—			—			—			0.2
Net transfers out of Level 3		—			(5.5		)	—			—			(5.5		)
Balance at the end of the period		$	1.7		$	6.1		$	0.9		$	(4.6	)	$	4.1
Net unrealized (losses) gains included in earnings related to instruments still held at the end of the period		$	(1.5	)	$	15.1		$	—		$	—		$	13.6
Realized and unrealized gains and losses included in earnings related to IES’s risk management assets and liabilities are recorded through nonregulated revenue or nonregulated cost of sales on the statements of income, 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, 2014						December 31, 2013
(Millions)		Carrying Amount			Fair Value			Carrying Amount			Fair Value
Long-term debt		$	3,056.20		$	3,076.40		$	3,056.20		$	3,031.60
Preferred stock of subsidiary		51.1			57.3			51.1			61.2
The fair values of long-term debt instruments are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. The fair values of preferred stock are estimated based on quoted market prices when available, or by using a perpetual dividend discount model. The fair values of long-term debt instruments and preferred stock are categorized within Level 2 of the fair value hierarchy.
Due to the short-term nature of cash and cash equivalents, accounts receivable, accounts payable, and outstanding commercial paper, the carrying amount for each of these items approximates fair value.

ADVERTISING_COSTS

ADVERTISING COSTS	3 Months Ended
	Mar. 31, 2014
Marketing and Advertising Expense [Abstract]	'
ADVERTISING COSTS	'
	Advertising Costs
	Costs associated with certain natural gas and electric direct-response advertising campaigns at IES were capitalized and reported as other long-term assets on the balance sheets. The capitalized costs result in probable future benefits and were incurred to solicit sales to customers who could be shown to have responded specifically to the advertising. Capitalized direct-response advertising costs, net of accumulated amortization, totaled $4.5 million and $5.2 million as of March 31, 2014, and December 31, 2013, respectively. The asset balances for each of the direct-response advertising cost pools are reviewed quarterly for impairment. We did not record any significant impairments during the three months ended March 31, 2014, and 2013.
	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 $1.3 million and $3.0 million for the three months ended March 31, 2014, and 2013, respectively.
	We expense all advertising costs as incurred, except for those capitalized as direct-response advertising, as discussed above. Other advertising expense was $1.7 million and $2.3 million for the three months ended March 31, 2014, and 2013, respectively.

REGULATORY_ENVIRONMENT

REGULATORY ENVIRONMENT	3 Months Ended
	Mar. 31, 2014
Regulated Operations [Abstract]	'
REGULATORY ENVIRONMENT	'
	Regulatory Environment
	Wisconsin
	2015 Rate Case
	In April 2014, WPS filed an application with the PSCW to increase retail electric rates $76.8 million and to decrease natural gas rates $1.6 million, with rates expected to be effective January 1, 2015. WPS's request reflects a 10.60% return on common equity and a target common equity ratio of 50.50% in WPS's regulatory capital structure. The proposed retail electric rate increase is primarily driven by the completion of a fuel refund to customers in 2014 rates, which kept rates flat in 2014, as well as a reduction in refunds associated with decoupling. In 2015, fuel and purchased power costs are expected to increase, as are transmission costs and general inflation. The proposed retail electric rate increase also includes WPS's request to recover deferred costs over four years related to the 2013 acquisition of the Fox Energy Center. Finally, capital costs associated with both previously approved environmental upgrades at the Columbia plant as well as our efforts to improve electric reliability by converting company distribution lines with lower performance history from overhead to underground are also contributing to the increase in retail electric rates. The proposed retail natural gas rate decrease is driven by 2013 decoupling over-collections, which will be refunded to customers in 2015. An increase in non-fuel operating and maintenance costs, including the impact of general inflation, and an increase in return on equity partially offset the effect of the 2013 decoupling over-collections.
	2014 Rates
	In December 2013, the PSCW issued a final written order for WPS, effective January 1, 2014. It authorized a net retail electric rate decrease of $12.8 million and a net retail natural gas rate increase of $4.0 million, reflecting a 10.20% return on common equity. The order also included a common equity ratio of 50.14% in WPS's regulatory capital structure. The retail electric rate impact consisted of a rate increase, including recovery of the difference between the 2012 fuel refund and the 2013 rate increase discussed below, entirely offset by a portion of estimated fuel cost over-collections from customers in 2013. Retail electric rates were decreased by 2012 decoupling over-collections to be returned to customers in 2014. The retail natural gas rate impact consisted of a rate decrease, which was more than offset by the positive impact of 2012 decoupling under-collections to be recovered from customers in 2014. Both the retail electric and retail natural gas rate changes included the recovery of pension and other employee benefit increases that were deferred in the 2013 rate case, as discussed below. The PSCW also authorized the recovery of prudently incurred 2014 environmental mitigation project costs related to compliance with a Consent Decree signed in January 2013 related to the Pulliam and Weston sites. See Note 11, Commitments and Contingencies, for more information. Additionally, the order required WPS to terminate its existing decoupling mechanism, beginning January 1, 2014.
	2013 Rates
	In December 2012, the PSCW issued a final written order for WPS, effective January 1, 2013. The order included a $28.5 million retail electric rate increase, partially offset by the actual 2012 fuel refund of $20.5 million. The difference between the 2012 fuel refund and the rate increase was deferred for recovery in 2014 rates. As a result, there was no change to customers' 2013 retail electric rates. The order also included a $3.4 million retail natural gas rate decrease. The rate changes included deferrals of $7.3 million for retail electric and $2.1 million for retail natural gas of pension and other employee benefit costs that are being recovered in 2014 rates. The order reflected a 10.30% return on common equity and a common equity ratio of 51.61% in WPS's regulatory capital structure. In addition, WPS was authorized recovery of $5.9 million related to income tax amounts previously expensed due to the Federal Health Care Reform Act. As a result, this amount was recorded as a regulatory asset in 2012, and recovery from customers began in 2013. The order also authorized the recovery of direct Cross State Air Pollution Rule (CSAPR) costs incurred through the end of 2012. Lastly, the order authorized WPS to switch from production tax credits to Section 1603 Grants for the Crane Creek wind project.
	A decoupling mechanism for natural gas and electric residential and small commercial and industrial customers was approved on a pilot basis as part of the order. The mechanism was based on total rate case-approved margins, rather than being calculated on a per-customer basis. The mechanism did not cover all customer classes, and it included 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 were subject to these caps.
	Michigan
	2014 MGU Rates
	In November 2013, the MPSC issued a final written order for MGU, effective January 1, 2014. The order authorized a retail natural gas rate increase of $4.5 million. The rates reflect a 10.25% return on common equity and a common equity ratio of 48.62% in MGU's regulatory capital structure. Additionally, the order required MGU to terminate its existing decoupling mechanism after December 31, 2013, and replace it with a new decoupling mechanism based on total margins, beginning January 1, 2015. The new decoupling mechanism does not cover variations in volumes due to actual weather being different from rate case-assumed weather. The rate order also terminated MGU's existing uncollectible expense true-up mechanism after December 31, 2013.
	MGU Depreciation Case
	In January 2013, the Michigan Court of Appeals issued an order reversing the MPSC's 2010 disallowance of $2.5 million associated with the early retirement of certain MGU assets. As a result, a $2.5 million reduction to depreciation expense was recorded in the first quarter of 2013. In June 2013, the MPSC issued an order related to MGU's most recent depreciation case. This order also approved a settlement agreement reflecting recovery of these previously disallowed costs.
	2014 UPPCO Rates
	In December 2013, the MPSC issued a final written order for UPPCO, effective January 1, 2014. The order authorized a retail electric rate increase of $5.8 million. The rates reflected a 10.15% return on common equity and a common equity ratio of 56.74% in UPPCO's regulatory capital structure. The order required UPPCO to terminate its existing decoupling mechanism after December 31, 2013. In addition, the order required UPPCO to achieve certain minimum line clearance performance metrics for recovery of costs related to clearing trees and other natural obstructions away from power lines. If these metrics are not achieved, or if the minimum spending level is not reached, UPPCO may be required to refund certain amounts to customers.
	Illinois
	2015 Rate Cases
	In February 2014, PGL and NSG filed applications with the ICC to increase retail natural gas rates $128.9 million and $7.1 million, respectively, with rates expected to be effective in early 2015. Both PGL's and NSG's requests reflect a 10.25% return on common equity. The requests reflect target common equity ratios of 50.41% for NSG and 50.31% for PGL in their respective regulatory capital structures. The proposed retail natural gas rate increases are primarily driven by increased capital investments, in particular for main replacement, a loss in revenues as a result of lower projected sales volumes, increased costs of debt and common equity, and increased operating expenses. The increase in operating expenses relates to pipeline safety and other compliance work, a general wage increase, higher depreciation costs, and higher invested capital taxes. PGL's application also removes from the proposed 2015 rates the investment and related expenses that PGL plans to recover through its new Qualifying Infrastructure Plant rider, as discussed below. PGL and NSG proposed no changes to the continued use of their decoupling mechanisms and uncollectible expense true-up mechanisms.
	Qualifying Infrastructure Plant (QIP) Rider
	In July 2013, Illinois Public Act 98-0057 (formerly Senate Bill 2266), The Natural Gas Consumer, Safety & Reliability Act, became law. The Act gives PGL a cost recovery mechanism for Illinois natural gas infrastructure upgrades that will be collected through a surcharge on customer bills. This Act eliminated a requirement for PGL and NSG to file biennial rate proceedings under existing Illinois coal-to-gas legislation. In September 2013, PGL filed with the ICC requesting the proposed rider, and the ICC approved the tariff in January 2014. The rider became effective on January 1, 2014.
	2013 Rates
	In June 2013, the ICC issued a final written order for PGL and NSG, effective June 27, 2013. The order authorized a retail natural gas rate increase of $57.2 million for PGL and $6.6 million for NSG. The rates for PGL reflected a 9.28% return on common equity and a common equity ratio of 50.43% in PGL's regulatory capital structure. The rates for NSG reflected a 9.28% return on common equity and a common equity ratio of 50.32% in NSG's regulatory capital structure. The rate order also allowed PGL and NSG to continue the use of their decoupling mechanisms, as affirmed by the Illinois Appellate Court (Court).
	In August 2013, the ICC granted certain rehearing requests on tax-related issues filed by PGL, NSG, and other intervenors. PGL and NSG asked for a correction of the revenue requirement for deferred tax assets related to tax net operating losses (NOLs) incurred in 2012 and 2013. In the ICC’s order, these deferred tax assets were included in rate base, but computational errors were made. Other intervenors requested the exclusion from rate base of the deferred tax asset related to the 2012 tax NOL. The tax NOLs in question resulted from PGL and NSG claiming accelerated depreciation deductions in 2012 and 2013. In December 2013, the ICC evaluated and approved a correction of the computational errors and rejected the intervenors' proposed exclusion of the 2012 tax NOL. Customer rates were increased by $2.6 million for PGL and $0.1 million for NSG for the impact of this correction, effective January 1, 2014. In January 2014, the Illinois Attorney General and Citizens Utility Board each filed an appeal with the Court.
	2012 Decoupling
	The ICC issued a final written order, effective January 21, 2012, which approved permanent decoupling mechanisms for PGL and NSG. The Illinois Attorney General and Citizens Utility Board appealed to the Court the ICC's authority to approve PGL's and NSG's decoupling mechanisms and filed a motion to stay the implementation of the permanent decoupling mechanism or make collections subject to refund. In May 2012, the ICC issued a revised amendatory order granting the Illinois Attorney General's motion to make revenues collected under the permanent decoupling mechanism subject to refund and directing PGL and NSG to track amounts that would be due to customers or the companies from the permanent decoupling mechanisms. Refunds would have been required if the Court found that the ICC did not have authority to approve decoupling and ordered a refund. As a result, the recovery of amounts related to decoupling in 2012 were uncertain, and PGL and NSG established offsetting reserves equal to decoupling amounts accrued. In March 2013, the Court issued an opinion that affirmed the ICC's order approving the permanent decoupling mechanism. As a result, the reserves recorded in 2012 were reversed in the first quarter of 2013. PGL's and NSG's permanent decoupling mechanism was in place for 2013. In June 2013, the Illinois Attorney General and Citizens Utility Board petitioned the Illinois Supreme Court to review the Court's decision. The Illinois Supreme Court granted the request in September 2013, and briefing is in progress. The Illinois Supreme Court has no deadline by which it must act. Decoupling amounts recorded in 2012 were fully recovered and amounts in 2013 are being refunded to customers in 2014. Decoupling amounts in 2014 will continue to be accrued, absent an adverse Illinois Supreme Court decision.
	Minnesota
	2014 Rate Case
	In September 2013, MERC filed an application with the MPUC to increase retail natural gas distribution rates by $14.2 million. MERC's request reflected a 10.75% return on common equity and a common equity ratio of 50.31% in MERC's regulatory capital structure. The request was primarily driven by general inflation, property taxes, improvements to customer service programs, efforts to expand the customer base which would have a positive rate effect in the future, and operating and maintenance projects to ensure reliability and safety for customers.
	In December 2013, the MPUC approved an interim rate order authorizing a retail natural gas rate increase for MERC of $10.5 million, effective January 1, 2014. The interim rates reflect a 9.70% return on common equity and a common equity ratio of 50.31% in MERC's regulatory capital structure. The interim rate increase is subject to refund pending the final rate order, which is expected in the fourth quarter of 2014.
	In April 2014, MERC filed rebuttal testimony in response to recommendations of the Department of Commerce and the Attorney General to increase retail natural gas rates by $2.9 million to $6.0 million. MERC's rebuttal testimony reflected a revised increase in retail natural gas rates of $12.2 million. The revised request is lower than the initial application and is primarily driven by increased sales volume forecasts and revised natural gas costs based on more recent data available. Lower pension and benefit cost estimates also contributed to the revised request. The revised request reflects a 10.75% return on common equity and a common equity ratio of 50.31% in MERC's regulatory capital structure, which did not change from the initial application.
	2011 Rates Finalized in 2013
	In July 2012, the MPUC approved a final written order for MERC, effective January 1, 2013. The order authorized a retail natural gas rate increase of $11.0 million. The rates reflected a 9.70% return on common equity and a common equity ratio of 50.48% in MERC's regulatory capital structure. In addition, the order set recovery of MERC's 2011 test-year pension expense at 2010 levels. The MPUC also approved a decoupling mechanism for MERC that covers residential and small commercial and industrial customers on a three-year trial basis, effective January 1, 2013. The decoupling mechanism does not adjust for variations in volumes resulting from changes in customer count compared to rate case levels. It includes an annual 10% cap based on distribution revenues approved in the rate case. Amounts recoverable from or refundable to customers are subject to this cap.

SEGMENTS_OF_BUSINESS

SEGMENTS OF BUSINESS	3 Months Ended
	Mar. 31, 2014
Segment Reporting [Abstract]	'
SEGMENTS OF BUSINESS	'
	Segments of Business
	At March 31, 2014, we reported five segments, which are described below.
	•	The natural gas utility segment includes the regulated natural gas utility operations of MERC, MGU, NSG, PGL, and WPS.
	•	The electric utility segment includes the regulated electric utility operations of UPPCO and WPS.
	•	The electric transmission investment segment includes our approximate 34% ownership interest in ATC. ATC is a federally regulated electric transmission company.
	•	IES is a diversified nonregulated retail energy supply and services company that primarily sells electricity and natural gas in deregulated markets. In addition, IES invests in energy assets with renewable attributes, primarily distributed solar assets.
	•	The holding company and other segment includes the operations of the Integrys Energy Group holding company, ITF, and the PELLC holding company, along with any nonutility activities at IBS, MERC, MGU, NSG, PGL, UPPCO, and WPS.
	The tables below present information related to our reportable segments:
			Regulated Operations											Nonutility and Nonregulated Operations
	(Millions)		Natural Gas			Electric			Electric		Total			IES			Holding			Reconciling			Integrys
			Utility			Utility			Transmission		Regulated						Company			Eliminations			Energy Group
									Investment		Operations						and Other						Consolidated
	Three Months Ended
	March 31, 2014
	External revenues		$	1,267.50		$	349.2		$	—	$	1,616.70		$	1,289.60		$	18.6		$	—		$	2,924.90
	Intersegment revenues		4.5			—			—		4.5			2.6			0.4			(7.5		)	—
	Depreciation and amortization expense		36.4			25.6			—		62			2.9			6.5			(0.1		)	71.3
	Earnings from equity method investments		—			—			22.5		22.5			0.1			0.3			—			22.9
	Miscellaneous income		0.3			3.5			—		3.8			0.3			5.4			(3.5		)	6
	Interest expense		13.4			11.7			—		25.1			0.5			17			(3.5		)	39.1
	Provision (benefit) for income taxes		66.7			18.1			8.8		93.6			5.9			(9.7		)	—			89.8
	Net income (loss) from continuing operations		99.2			31.8			13.7		144.7			10.9			(2.4		)	—			153.2
	Discontinued operations		—			—			—		—			(0.1		)	—			—			(0.1		)
	Preferred stock dividends of subsidiary		(0.1		)	(0.7		)	—		(0.8		)	—			—			—			(0.8		)
	Noncontrolling interest in subsidiaries		—			—			—		—			—			0.1			—			0.1
	Net income (loss) attributed to common shareholders		99.1			31.1			13.7		143.9			10.8			(2.3		)	—			152.4
			Regulated Operations											Nonutility and Nonregulated Operations
	(Millions)		Natural Gas			Electric			Electric		Total			IES			Holding			Reconciling			Integrys
			Utility			Utility			Transmission		Regulated						Company			Eliminations			Energy Group
									Investment		Operations						and Other						Consolidated
	Three Months Ended
	31-Mar-13
	External revenues		$	792		$	331.8		$	—	$	1,123.80		$	545.4		$	9		$	—		$	1,678.20
	Intersegment revenues		1.9			—			—		1.9			0.3			0.4			(2.6		)	—
	Depreciation and amortization expense		32.2			21.5			—		53.7			2.7			4.6			(0.1		)	60.9
	Earnings from equity method investments		—			—			21.7		21.7			0.2			0.4			—			22.3
	Miscellaneous income		0.2			1.6			—		1.8			0.4			7.2			(3.7		)	5.7
	Interest expense		12.7			9.1			—		21.8			0.5			10.7			(3.7		)	29.3
	Provision (benefit) for income taxes		63.3			16.1			8.3		87.7			27.3			(5.4		)	—			109.6
	Net income (loss) from continuing operations		89.8			29.3			13.4		132.5			51.3			(1.6		)	—			182.2
	Discontinued operations		—			—			—		—			0.1			6			—			6.1
	Preferred stock dividends of subsidiary		(0.1		)	(0.7		)	—		(0.8		)	—			—			—			(0.8		)
	Net income attributed to common shareholders		89.7			28.6			13.4		131.7			51.4			4.4			—			187.5

NEW_ACCOUNTING_PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS	3 Months Ended
	Mar. 31, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
NEW ACCOUNTING PRONOUNCEMENTS	'
	New Accounting Pronouncements
	Recently Issued Accounting Guidance Not Yet Effective
	Accounting Standards Update (ASU) 2014-08, "Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity," was issued in April 2014. The guidance raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. The guidance is effective for us for the reporting period ending March 31, 2015. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date.
	ASU 2014-01, "Accounting for Investments in Qualified Affordable Housing Projects," was issued in January 2014. The guidance allows investors to use the proportional amortization method to account for investments in qualified affordable housing projects if certain conditions are met. Under that method, which replaces the effective yield method, an investor amortizes the cost of its investment, in proportion to the tax credits and other tax benefits it receives, to income tax expense. The guidance also requires new disclosures for all investments in these types of projects. The guidance is effective for us for the reporting period ending March 31, 2015. Although we have investments in affordable housing projects, adoption of this guidance is not expected to have a significant impact on our financial statements.

FINANCIAL_INFORMATION_Policies

FINANCIAL INFORMATION (Policies)	3 Months Ended
	Mar. 31, 2014
Accounting policies	'
Consolidation	'
	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.
Basis of accounting	'
	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, 2013. Financial results for an interim period may not give a true indication of results for the year.
	In management’s opinion, these unaudited financial statements include all adjustments necessary for a fair presentation of financial results. All adjustments are normal and recurring, unless otherwise noted. All intercompany transactions have been eliminated in consolidation.
Reclassification	'
	Assets and liabilities associated with the pending sale of UPPCO were reclassified as held for sale on our December 31, 2013, balance sheet to be consistent with the current period presentation. See Note 5, Dispositions, for more information on the pending sale of UPPCO.
Cash and cash equivalents	'
	Short-term investments with an original maturity of three months or less are reported as cash equivalents.
Inventory	'
	PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the Last-in, First-out (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.
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.
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. As the obligation for the shares issuable under the deferred compensation plan is accounted for as a liability, the numerator is adjusted for any changes in income or loss that would have resulted had it been accounted for as an equity instrument during the period.
Fair value measurements	'
	A fair value measurement is required to reflect the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model.
	Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities.
	Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:
	Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
	Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.
	Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.
	Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
	We primarily determine fair value using a market-based approach that uses observable market inputs where available, and internally developed inputs only when 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), and price correlation (for cross commodity contracts). These inputs are available through multiple sources, including exchanges and brokers. 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 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 department 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. Changes to the fair value inputs are made if necessary.
	We conduct a thorough review of fair value hierarchy classifications on a quarterly basis.
Fair value transfers	'
	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 at the value as of the end of the reporting period.
Advertising costs	'
	Costs associated with certain natural gas and electric direct-response advertising campaigns at IES were capitalized and reported as other long-term assets on the balance sheets. The capitalized costs result in probable future benefits and were incurred to solicit sales to customers who could be shown to have responded specifically to the advertising. Capitalized direct-response advertising costs, net of accumulated amortization, totaled $4.5 million and $5.2 million as of March 31, 2014, and December 31, 2013, respectively. The asset balances for each of the direct-response advertising cost pools are reviewed quarterly for impairment. We did not record any significant impairments during the three months ended March 31, 2014, and 2013.
	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 $1.3 million and $3.0 million for the three months ended March 31, 2014, and 2013, respectively.
	We expense all advertising costs as incurred, except for those capitalized as direct-response advertising, as discussed above. Other advertising expense was $1.7 million and $2.3 million for the three months ended March 31, 2014, and 2013, respectively.
New accounting pronouncements	'
	Accounting Standards Update (ASU) 2014-08, "Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity," was issued in April 2014. The guidance raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. The guidance is effective for us for the reporting period ending March 31, 2015. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date.
	ASU 2014-01, "Accounting for Investments in Qualified Affordable Housing Projects," was issued in January 2014. The guidance allows investors to use the proportional amortization method to account for investments in qualified affordable housing projects if certain conditions are met. Under that method, which replaces the effective yield method, an investor amortizes the cost of its investment, in proportion to the tax credits and other tax benefits it receives, to income tax expense. The guidance also requires new disclosures for all investments in these types of projects. The guidance is effective for us for the reporting period ending March 31, 2015. Although we have investments in affordable housing projects, adoption of this guidance is not expected to have a significant impact on our financial statements.
Stock options	'
Information related to share based awards	'
Stock-based compensation	'
	The fair value of stock option awards granted is estimated using a binomial lattice model. The expected term of option awards is derived from the output of the binomial lattice model 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. The expected stock price volatility is estimated using the 10-year historical volatility of our stock price.
Performance stock rights	'
Information related to share based awards	'
Stock-based compensation	'
	The fair values of performance stock rights are estimated using a Monte Carlo valuation model. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. The expected stock price volatility is estimated using two to three years of historical data.
Nonemployee director deferred stock units	'
Information related to share based awards	'
Stock-based compensation	'
	Each nonemployee director is granted deferred stock units (DSUs), typically in January of each year. These awards generally vest over one year; therefore, the expense is recognized pro-rata over the year in which the grant occurs. The number of DSUs granted is calculated by dividing a set dollar amount by our closing common stock price on December 31 of the prior year. Nonemployee directors also receive forfeitable dividend equivalents in the form of additional DSU's.

CASH_AND_CASH_EQUIVALENTS_Tabl

CASH AND CASH EQUIVALENTS (Tables)	3 Months Ended
	Mar. 31, 2014
Cash and Cash Equivalents [Abstract]	'
Table of significant noncash transactions	'
	Significant noncash transactions were:
		Three Months Ended March 31
	(Millions)	2014		2013
	Construction costs funded through accounts payable	$	92.3	$	59.8
	Equity issued for employee stock ownership plan	1.7		2.7
	Equity issued for stock-based compensation plans	—		16
	Equity issued for reinvested dividends	—		3

RISK_MANAGEMENT_ACTIVITIES_Tab

RISK MANAGEMENT ACTIVITIES (Tables)	3 Months Ended
	Mar. 31, 2014
Risk management activities	'
Assets and liabilities from risk management activities	'
	The following tables show our assets and liabilities from risk management activities:
					March 31, 2014
	(Millions)		Balance Sheet Presentation (1)		Assets from				Liabilities from
					Risk Management Activities				Risk Management Activities
	Utility Segments
	Nonhedge derivatives
	Natural gas contracts		Current		$	12.3			$	0.3
	Natural gas contracts		Long-term		1				0.1
	Financial transmission rights (FTRs) (2)		Current		0.9				0.2
	Petroleum product contracts		Current		0.1				—
	Coal contracts		Current		—				1.1
	Coal contracts		Long-term		1.8				0.4
	Nonregulated Segments
	Nonhedge derivatives
	Natural gas contracts		Current		56				41.7
	Natural gas contracts		Long-term		20.9				10.9
	Electric contracts		Current		200.8				132.5
	Electric contracts		Long-term		36.6				34.8
			Current		270.1				175.8
			Long-term		60.3				46.2
	Total				$	330.4			$	222
	(1)	We classify assets and liabilities from risk management activities as current or long-term based on the maturities of the underlying contracts.
	(2)	Includes a $0.2 million risk management asset that was classified as held for sale at UPPCO. See Note 5, Dispositions, for more information.
					31-Dec-13
	(Millions)		Balance Sheet Presentation (1)		Assets from				Liabilities from
					Risk Management Activities				Risk Management Activities
	Utility Segments
	Nonhedge derivatives
	Natural gas contracts		Current		$	8.3			$	1
	Natural gas contracts		Long-term		1.8				0.1
	FTRs (2)		Current		2.1				0.3
	Petroleum product contracts		Current		0.1				—
	Coal contracts		Current		—				1.9
	Coal contracts		Long-term		0.2				0.8
	Nonregulated Segments
	Nonhedge derivatives
	Natural gas contracts		Current		57.6				42.9
	Natural gas contracts		Long-term		29.5				18.6
	Electric contracts		Current		172				117.7
	Electric contracts		Long-term		43.9				43.3
			Current		240.1				163.8
			Long-term		75.4				62.8
	Total				$	315.5			$	226.6
	(1)	We classify assets and liabilities from risk management activities as current or long-term based on the maturities of the underlying contracts.
	(2)	Includes a $0.6 million risk management asset that was classified as held for sale at UPPCO. See Note 5, Dispositions, for more information.
Potential effect of netting arrangements on our financial position for recognized derivative assets and liabilities	'
	The following tables show the potential effect on our financial position of netting arrangements for recognized derivative assets and liabilities:
			March 31, 2014
	(Millions)		Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements
	Utility segments		$	14.3			$	0.6			$	13.7
	Nonregulated segments		314				193				121
	Total		328.3				193.6				134.7
	Derivative assets not subject to master netting or similar arrangements		2.1								2.1
	Total risk management assets		$	330.4							$	136.8
	Derivative liabilities subject to master netting or similar arrangements
	Utility segments		$	0.6			$	0.6			$	—
	Nonregulated segments		219.8				193				26.8
	Total		220.4				193.6				26.8
	Derivative liabilities not subject to master netting or similar arrangements		1.6								1.6
	Total risk management liabilities		$	222							$	28.4
			31-Dec-13
	(Millions)		Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements
	Utility segments		$	12.3			$	2.1			$	10.2
	Nonregulated segments		301.9				178.1				123.8
	Total		314.2				180.2				134
	Derivative assets not subject to master netting or similar arrangements		1.3								1.3
	Total risk management assets		$	315.5							$	135.3
	Derivative liabilities subject to master netting or similar arrangements
	Utility segments		$	1.4			$	1.4			$	—
	Nonregulated segments		222.1				178.1				44
	Total		223.5				179.5				44
	Derivative liabilities not subject to master netting or similar arrangements		3.1								3.1
	Total risk management liabilities		$	226.6							$	47.1
Cash collateral positions	'
	The following table shows our cash collateral positions:
	(Millions)		March 31, 2014				December 31, 2013
	Cash collateral provided to others:
	Related to contracts under master netting or similar arrangements (1)		$	74.6			$	37.6
	Other		1.1				1.1
	Cash collateral received from others related to contracts under master netting or similar arrangements (2)		1.5				0.7
	(1)	Includes $1.3 million of cash collateral provided to others that was classified as held for sale at UPPCO at March 31, 2014 and December 31, 2013. See Note 5, Dispositions, for more information.
	(2)	Reflected in other current liabilities on the balance sheets.
Derivatives with credit risk-related contingent features that were in a liability position	'
	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, 2014				December 31, 2013
	Utility segments		$	0.2			$	0.6
	Nonregulated segments		58.4				76.7
Collateral requirements related to credit-risk related contingent features in commodity instruments	'
	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, 2014				December 31, 2013
	Collateral that would have been required:
	Utility segments		$	—			$	—
	Nonregulated segments		199.7				197.6
	Collateral already satisfied:
	Nonregulated segments — Letters of credit		20				4.5
	Collateral remaining:
	Nonregulated segments		179.7				193.1
Utility segments	'
Risk management activities	'
Notional volumes of outstanding non-hedge derivative contracts	'
	The notional volumes of outstanding derivative contracts at the utilities and IBS were as follows:
			March 31, 2014									December 31, 2013
	(Millions, except barrels)		Purchases			Sales			Other Transactions			Purchases	Sales	Other Transactions
	Natural gas (therms)		2,438.80			2.1			N/A			3,124.80	29.3	N/A
	FTRs (kilowatt-hours)		N/A			N/A			1,448.70			N/A	N/A	3,633.10
	Petroleum products (barrels)		113,000.00			20,000.00			N/A			102,811.00	14,000.00	N/A
	Coal (tons)		4.3			—			N/A			4.8	—	N/A
Unrealized gains (losses) related to non-hedge derivatives	'
	The table below shows the unrealized gains (losses) recorded related to derivative contracts at the utilities and IBS:
					Three Months Ended March 31
	(Millions)		Financial Statement Presentation		2014				2013
	Natural gas		Balance Sheet — Regulatory assets (current)		$	0.9			$	13
	Natural gas		Balance Sheet — Regulatory assets (long-term)		(0.2		)		0.8
	Natural gas		Balance Sheet — Regulatory liabilities (current)		3.4				5.9
	Natural gas		Balance Sheet — Regulatory liabilities (long-term)		(0.4		)		0.8
	Natural gas		Income Statement — Operating and maintenance expense		0.2				0.2
	FTRs		Balance Sheet — Regulatory assets (current)		0.2				0.2
	FTRs		Balance Sheet — Regulatory liabilities (current)		(0.2		)		(0.4		)
	Coal		Balance Sheet — Regulatory assets (current)		0.2				1.9
	Coal		Balance Sheet — Regulatory assets (long-term)		0.4				2.3
	Coal		Balance Sheet — Regulatory liabilities (current)		—				(0.2		)
	Coal		Balance Sheet — Regulatory liabilities (long-term)		1.6				(2.2		)
Nonregulated segments	'
Risk management activities	'
Notional volumes of outstanding non-hedge derivative contracts	'
	IES had the following notional volumes of outstanding derivative contracts:
			March 31, 2014						December 31, 2013
	(Millions)		Purchases			Sales			Purchases			Sales
	Commodity contracts
	Natural gas (therms)		919.2			774.3			1,199.90			1,065.40
	Electric (kilowatt-hours)		40,473.70			25,245.00			49,186.30			30,813.80
Gains (losses) related to non-hedge derivatives	'
	Gains (losses) related to derivative contracts are recognized currently in earnings, as shown in the table below:
					Three Months Ended March 31
	(Millions)		Income Statement Presentation		2014				2013
	Natural gas		Nonregulated revenue		$	(36.9	)		$	3.4
	Natural gas		Nonregulated cost of sales		33				(1.6		)
	Natural gas		Nonregulated revenue (reclassified from accumulated OCI) *		—				(0.1		)
	Electric		Nonregulated revenue		160.3				64
	Electric		Nonregulated cost of sales		0.6				—
	Electric		Nonregulated revenue (reclassified from accumulated OCI) *		—				(1.0		)
	Total				$	157			$	64.7
	*	Represents amounts reclassified from accumulated other comprehensive loss (OCI) related to cash flow hedges that were dedesignated in prior periods.

ACQUISITIONS_Tables

ACQUISITIONS (Tables) (Fox Energy Company LLC)	3 Months Ended
	Mar. 31, 2014
Fox Energy Company LLC	'
Acquisitions	'
Schedule of purchase price allocation	'
	The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:
	(Millions)
	Assets acquired (1)
	Inventories		$	3
	Other current assets		0.4
	Property, plant, and equipment		374.4
	Other long-term assets (2)		15.6
	Total assets acquired		$	393.4
	Liabilities assumed
	Accounts payable		$	1.8
	Total liabilities assumed		$	1.8
	(1)	Relates to the electric utility segment.
	(2)	Intangible assets recorded for contractual services agreements. See Note 8, Goodwill and Other Intangible Assets, for more information.

DISPOSITIONS_Tables

DISPOSITIONS (Tables) (UPPCO)	3 Months Ended
	Mar. 31, 2014
UPPCO	'
Dispositions	'
Carrying values of major classes of assets and liabilities classified as held for sale on balance sheets	'
	The following table shows the carrying values of the major classes of assets and liabilities related to UPPCO classified as held for sale on the balance sheets:
	(Millions)	March 31, 2014		31-Dec-13
	Current assets	$	27.2	$	26.5
	Property, plant, and equipment, net of accumulated depreciation of $90.2 and $88.9, respectively	193.2		193.8
	Other long-term assets	65.6		51.6
	Total assets	$	286	$	271.9
	Current liabilities	$	12	$	16.7
	Long-term liabilities	24.7		32.4
	Total liabilities	$	36.7	$	49.1

INVESTMENT_IN_ATC_Tables

INVESTMENT IN ATC (Tables) (ATC)	3 Months Ended
	Mar. 31, 2014
ATC	'
Schedule of Equity Method Investments	'
Schedule of changes to Integrys Energy Group's investment in ATC	'
	The following table shows changes to our investment in ATC:
		Three Months Ended March 31
	(Millions)	2014		2013
	Balance at the beginning of period	$	508.4	$	476.6
	Add: Earnings from equity method investment	22.5		21.7
	Add: Capital contributions	5.1		1.7
	Less: Dividends received	18.4		17.3
	Balance at the end of period	$	517.6	$	482.7
Summarized income statement information of ATC	'
	Financial data for all of ATC is included in the following tables:
		Three Months Ended March 31
	(Millions)	2014		2013
	Income statement data
	Revenues	$	163.3	$	151.8
	Operating expenses	78.6		69.8
	Other expense	21.6		21.5
	Net income	$	63.1	$	60.5
Summarized balance sheet information of ATC	'
	(Millions)	March 31, 2014		31-Dec-13
	Balance sheet data
	Current assets	$	79.2	$	80.7
	Noncurrent assets	3,563.90		3,509.50
	Total assets	$	3,643.10	$	3,590.20
	Current liabilities	$	301.4	$	381.5
	Long-term debt	1,650.00		1,550.00
	Other noncurrent liabilities	131.2		126.1
	Shareholders’ equity	1,560.50		1,532.60
	Total liabilities and shareholders’ equity	$	3,643.10	$	3,590.20

GOODWILL_AND_OTHER_INTANGIBLE_1

GOODWILL AND OTHER INTANGIBLE ASSETS (Tables)	3 Months Ended
	Mar. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]	'
Schedule of identifiable intangible assets other than goodwill	'
	The identifiable intangible assets other than goodwill listed below are part of other current and long-term assets on the balance sheets. An insignificant amount was recorded as assets held for sale on the balance sheets.
			March 31, 2014							31-Dec-13
	(Millions)		Gross Carrying		Accumulated			Net Carrying		Gross Carrying		Accumulated			Net Carrying
			Amount		Amortization			Amount		Amount		Amortization			Amount
	Amortized intangible assets
	Customer-related (1)		$	26.8	$	(16.1	)	$	10.7	$	26.8	$	(15.7	)	$	11.1
	Contractual service agreements (2)		15.6		(2.4		)	13.2		15.6		(1.8		)	13.8
	Renewable energy credits (3)		9.6		—			9.6		8.4		—			8.4
	Compressed natural gas fueling contract assets (4)		5.6		(2.9		)	2.7		5.6		(2.7		)	2.9
	Customer-owned equipment modifications (5)		4		(0.9		)	3.1		4		(0.9		)	3.1
	Natural gas and electric contract assets (6)		3.9		(1.2		)	2.7		3.9		(0.5		)	3.4
	Nonregulated easements (7)		3.7		(1.2		)	2.5		3.7		(1.1		)	2.6
	Patents/intellectual property (8)		3.4		(0.6		)	2.8		3.4		(0.5		)	2.9
	Other		0.5		(0.3		)	0.2		0.5		(0.3		)	0.2
	Total		$	73.1	$	(25.6	)	$	47.5	$	71.9	$	(23.5	)	$	48.4
	Unamortized intangible assets
	MGU trade name		$	5.2	$	—		$	5.2	$	5.2	$	—		$	5.2
	Trillium trade name (9)		3.5		—			3.5		3.5		—			3.5
	Pinnacle trade name (9)		1.5		—			1.5		1.5		—			1.5
	Total intangible assets		$	83.3	$	(25.6	)	$	57.7	$	82.1	$	(23.5	)	$	58.6
	(1)	Represents customer relationship assets associated with PELLC’s former nonregulated retail natural gas and electric operations, ITF's compressed natural gas fueling operations, and IES's retail natural gas operations. The remaining weighted-average amortization period for customer-related intangible assets at March 31, 2014, was approximately 11 years.
	(2)	Represents contractual service agreements related to maintenance on the combustion turbine generators at the Fox Energy Center. The remaining amortization period for these intangible assets at March 31, 2014, was approximately six years.
	(3)	Used at IES to comply with state Renewable Portfolio Standards and to support customer commitments.
	(4)	Represents the fair value of ITF contracts acquired in September 2011. The remaining amortization period at March 31, 2014, was approximately seven years.
	(5)	Relates to modifications made by IES and ITF to customer-owned equipment. These intangible assets are amortized on a straight-line basis, with a remaining weighted-average amortization period at March 31, 2014, of approximately ten years.
	(6)	Represents the fair value of certain natural gas and electric customer contracts acquired by IES during 2013 that were not considered to be derivative instruments. The remaining amortization period for these intangible assets at March 31, 2014, was approximately four years.
	(7)	Relates to easements supporting a pipeline at IES. The easements are amortized on a straight-line basis, with a remaining amortization period at March 31, 2014, of approximately ten years.
	(8)	Represents the fair value of patents/intellectual property at ITF related to a system for more efficiently compressing natural gas to allow for faster fueling. The remaining amortization period at March 31, 2014, was approximately eight years.
	(9)	Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) are wholly-owned subsidiaries of ITF.
Schedule of intangible asset amortization expense for the next five years	'
	The following table shows our estimated amortization expense for the next five years, including amounts recorded through March 31, 2014:
			For the Year Ending December 31
	(Millions)		2014		2015			2016		2017		2018
	Amortization to be recorded in nonregulated cost of sales		$	3.4	$	2		$	1.1	$	0.9	$	0.8
	Amortization to be recorded in depreciation and amortization expense		4.3		4.2			4		3.9		3.8

SHORTTERM_DEBT_AND_LINES_OF_CR1

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)	3 Months Ended
	Mar. 31, 2014
Short-term Debt [Abstract]	'
Schedule of short-term borrowings	'
	Our outstanding short-term borrowings were as follows:
	(Millions, except percentages)	March 31, 2014				31-Dec-13
	Commercial paper	$	321.9			$	326
	Average interest rate on commercial paper	0.23		%		0.22		%
Schedule of revolving credit facilities and remaining available capacity	'
	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 as of March 31:
	(Millions)	Maturity		March 31, 2014				31-Dec-13
	Revolving credit facility (Integrys Energy Group)	5/17/14		$	275			$	275
	Revolving credit facility (Integrys Energy Group)	5/17/16		200				200
	Revolving credit facility (Integrys Energy Group)	6/13/17		635				635
	Revolving credit facility (WPS)	5/17/14		135				135
	Revolving credit facility (WPS)	6/13/17		115				115
	Revolving credit facility (PGL)	6/13/17		250				250
	Total short-term credit capacity			$	1,610.00			$	1,610.00
	Less:
	Letters of credit issued inside credit facilities			$	70.6			$	52.4
	Commercial paper outstanding			321.9				326
	Available capacity under existing agreements			$	1,217.50			$	1,231.60

INCOME_TAXES_Tables

INCOME TAXES (Tables)	3 Months Ended
	Mar. 31, 2014
Income Tax Disclosure [Abstract]	'
Schedule of effective tax rates	'
	The table below shows our effective tax rates attributable to continuing operations:
		Three Months Ended March 31
		2014		2013
	Effective tax rate	37	%	37.6	%

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Tables)	3 Months Ended
	Mar. 31, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Schedule of minimum future commitments related to purchase obligations	'
	The following table shows our minimum future commitments related to these purchase obligations as of March 31, 2014, including those of our subsidiaries.
						Payments Due By Period
	(Millions)		Year Contracts Extend Through	Total Amounts Committed		2014		2015		2016		2017		2018		Later Years
	Natural gas utility supply and transportation		2028	$	793.7	$	128.2	$	169.7	$	158.5	$	122.6	$	71.7	$	143
	Electric utility
	Purchased power *		2029	918		59.8		49.4		42.8		53.2		54		658.8
	Coal supply and transportation		2018	94.6		47		28.5		9.9		5.9		3.3		—
	Nonregulated electricity and natural gas supply		2020	600.9		376.4		161.2		51.9		9.4		1.6		0.4
	Total			$	2,407.20	$	611.4	$	408.8	$	263.1	$	191.1	$	130.6	$	802.2
	*	Includes minimum future commitments for UPPCO related to power purchase contracts of $8.2 million for the years 2014 to 2024. In January 2014, we announced an agreement to sell UPPCO. See Note 5, Dispositions, for more information.

GUARANTEES_Tables

GUARANTEES (Tables)	3 Months Ended
	Mar. 31, 2014
Guarantees [Abstract]	'
Schedule of outstanding guarantees	'
	The following table shows our outstanding guarantees:
			Total Amounts Committed		Expiration
	(Millions)		at March 31, 2014		Less Than 1 Year		1 to 3 Years		Over 3 Years
	Guarantees supporting commodity transactions of subsidiaries (1) (5)		$	684.5	$	412.6	$	31.7	$	240.2
	Standby letters of credit (2) (5)		74.1		70.7		3.3		0.1
	Surety bonds (3)		29.1		29.1		—		—
	Other guarantees (4) (5)		55.3		1.5		—		53.8
	Total guarantees		$	843	$	513.9	$	35	$	294.1
	(1)	Consists of (a) $497.7 million, $5.0 million, and $2.0 million to support the business operations of IES, IBS, and UPPCO, respectively, and (b) $126.7 million, $52.9 million, and $0.2 million related to natural gas supply at MERC, MGU and ITF, respectively. 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 $72.1 million issued to support IES’s operations and $2.0 million issued to support ITF, MERC, MGU, NSG, PGL, UPPCO, and WPS. These amounts are not reflected on our balance sheets.
	(3)	Primarily for the construction and operation of compressed natural gas fueling stations, 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) $35.0 million to support IES's future payment obligations related to its distributed solar generation projects. This guarantee is not reflected on our balance sheets; (b) $10.0 million related to the sale agreement for IES's 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 law; (c) $1.8 million related to the sale of WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC. IES's guaranteed the buyer's performance under certain derivative contracts that the buyer assumed from WPS Empire State, Inc. in conjunction with the sale; (d) $2.4 million related to the performance of an operating and maintenance agreement by ITF; and (e) $6.1 million related to other indemnifications primarily for workers compensation coverage. The amounts discussed in items (c) through (e) above are not reflected on our balance sheets.
	(5)	Consists of $3.4 million of guarantees related to UPPCO. See Note 5, Dispositions, for more information on the pending sale of UPPCO.

EMPLOYEE_BENEFIT_PLANS_Tables

EMPLOYEE BENEFIT PLANS (Tables)	3 Months Ended
	Mar. 31, 2014
Compensation and Retirement Disclosure [Abstract]	'
Schedule of the components of net periodic benefit cost	'
	The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans:
		Pension Benefits						Other Postretirement Benefits
		Three Months Ended March 31						Three Months Ended March 31
	(Millions)	2014			2013			2014			2013
	Service cost	$	6.6		$	7.5		$	5.9		$	6.5
	Interest cost	19.7			17.8			7.1			6.3
	Expected return on plan assets	(28.9		)	(26.6		)	(8.8		)	(7.7		)
	Amortization of prior service cost (credit)	0.2			1			(1.3		)	(0.6		)
	Amortization of net actuarial loss	8.4			13.5			0.7			2
	Net periodic benefit cost	$	6		$	13.2		$	3.6		$	6.5

STOCKBASED_COMPENSATION_Tables

STOCK-BASED COMPENSATION (Tables)	3 Months Ended
	Mar. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Schedule of stock-based compensation expense and the related deferred tax benefit recognized in income	'
	The following table reflects the stock-based compensation expense and the related deferred income tax benefit recognized in income for the three months ended March 31:
	(Millions)		2014			2013
	Stock options		$	0.3		$	0.4
	Performance stock rights		0.5			2.2
	Restricted share units		3.1			2.8
	Nonemployee director deferred stock units		0.2			0.3
	Total stock-based compensation expense		$	4.1		$	5.7
	Deferred income tax benefit		$	1.6		$	2.3
Schedule of the assumptions incorporated into the valuation of stock options granted	'
	The following table shows the assumptions incorporated into the valuation model:
			February 2014 Grant
	Expected term		8 years
	Risk-free interest rate		0.12% – 2.88%
	Expected dividend yield		5.28%
	Expected volatility		18%
Summary of stock option activity and information related to outstanding and exercisable stock options	'
	A summary of stock option activity for the three months ended March 31, 2014, and information related to outstanding and exercisable stock options at March 31, 2014, is presented below:
			Stock Options		Weighted-Average			Weighted-Average	Aggregate
					Exercise Price Per			Remaining	Intrinsic Value
					Share			Contractual Life	(Millions)
								(in Years)
	Outstanding at December 31, 2013		1,550,374		$	50.93
	Granted		264,332		55.23
	Exercised		(11,504	)	45.45
	Outstanding at March 31, 2014		1,803,202		$	51.6		6.6	$	14.5
	Exercisable at March 31, 2014		1,114,027		$	49.75		5.1	$	11
Schedule of assumptions incorporated into the valuation models for performance stock rights	'
	The table below reflects the assumptions used in the valuation of the outstanding grants at March 31:
			2014
	Risk-free interest rate		0.34% – 0.57%
	Expected dividend yield		5.28% – 5.33%
	Expected volatility		15% – 22%
Information related to share based awards	'
Summary of the activity related to restricted share unit awards (equity and liability awards)	'
	A summary of the activity related to all restricted share unit awards (equity and liability awards) for the three months ended March 31, 2014, is presented below:
			Restricted Share		Weighted-Average Grant Date Fair Value
			Unit Awards
	Outstanding at December 31, 2013		511,301		$	52.24
	Granted		214,953		55.23
	Dividend equivalents		6,169		54.45
	Vested and released		(204,322	)	49.73
	Forfeited		(781	)	54.42
	Outstanding at March 31, 2014		527,320		$	54.45
Performance Stock Rights Accounted For As Equity Awards	'
Information related to share based awards	'
Summary of the activity related to performance stock rights	'
	A summary of the activity for the three months ended March 31, 2014, related to performance stock rights accounted for as equity awards is presented below:
			Performance		Weighted-Average
			Stock Rights		Fair Value *
	Outstanding at December 31, 2013		85,749		$	46.62
	Granted		21,146		44.28
	Adjustment for shares not distributed		(45,748	)	43.29
	Outstanding at March 31, 2014		61,147		$	48.31
	*	Reflects the weighted-average fair value used to measure equity awards. Equity awards are measured using the grant date fair value or the fair value on the modification date.
Performance Stock Rights Accounted For As Liability Awards	'
Information related to share based awards	'
Summary of the activity related to performance stock rights	'
	A summary of the activity for the three months ended March 31, 2014, related to performance stock rights accounted for as liability awards is presented below:
			Performance
			Stock Rights
	Outstanding at December 31, 2013		198,904
	Granted		84,529
	Adjustment for shares not distributed		(39,001	)
	Outstanding at March 31, 2014		244,432

COMMON_EQUITY_Tables

COMMON EQUITY (Tables)	3 Months Ended
	Mar. 31, 2014
Stockholders' Equity Note [Abstract]	'
Roll forward of issued common stock	'
	We had the following changes to issued common stock during the three months ended March 31, 2014:
	Balance at December 31, 2013		79,919,176
	Shares issued
	Employee Stock Ownership Plan		31,764
	Stock Investment Plan		12,151
	Balance at March 31, 2014		79,963,091
Schedule of common stock activity to meet requirements of our stock investment plan and stock-based employee benefit and compensation plans	'
	The following table provides a summary of common stock activity to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans:
	Period		Method of meeting requirements
	Beginning 02/05/14		Purchasing shares on the open market
	02/05/2013 – 02/04/2014		Issued new shares
	01/01/2013 – 02/04/2013		Purchased shares on the open market
Reconciliation of shares issued and outstanding	'
	The following table reconciles common shares issued and outstanding:
			March 31, 2014							December 31, 2013
			Shares			Average Cost *				Shares			Average Cost *
	Common stock issued		79,963,091							79,919,176
	Less:
	Deferred compensation rabbi trust		428,720			$	48.6			473,796			$	48.5
	Total common shares outstanding		79,534,371							79,445,380
	*	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	'
	The following table reconciles our computation of basic and diluted earnings per share:
			Three Months Ended March 31
	(Millions, except per share amounts)		2014				2013
	Numerator:
	Net income from continuing operations		$	153.2			$	182.2
	Discontinued operations, net of tax		(0.1		)		6.1
	Preferred stock dividends of subsidiary		(0.8		)		(0.8		)
	Noncontrolling interest in subsidiaries		0.1				—
	Net income attributed to common shareholders		$	152.4			$	187.5
	Denominator:
	Average shares of common stock — basic		80.2				78.7
	Effect of dilutive securities
	Stock-based compensation		0.3				0.4
	Deferred compensation		—				0.2
	Average shares of common stock — diluted		80.5				79.3
	Earnings per common share
	Basic		$	1.9			$	2.38
	Diluted		1.89				2.37
Schedule of antidilutive securities	'
	The calculation of diluted earnings per share excluded the following weighted-average outstanding securities that had an anti-dilutive effect:
			Three Months Ended March 31
	(Millions)		2014			2013
	Stock-based compensation		0.7			0.2
	Deferred compensation		0.3			—
Capital transactions with subsidiaries	'
	During the three months ended March 31, 2014, capital transactions with subsidiaries were as follows (in millions):
	Subsidiary		Dividends To Parent				Return Of				Equity Contributions
							Capital To Parent				From Parent
	IBS		$	—			$	—			$	15
	ITF (1)		—				—				17.4
	MERC		—				18				—
	MGU		—				7				—
	UPPCO		—				3.5				—
	WPS		28				—				—
	WPS Investments, LLC (2)		18.3				—				5.1
	Total		$	46.3			$	28.5			$	37.5
	(1)	ITF is a direct wholly owned subsidiary of PELLC. As a result, it makes distributions to PELLC, and receives equity contributions from PELLC. Subject to applicable law, PELLC does not have any dividend restrictions or limitations on distributions to us.
	(2)	WPS Investments, LLC is a consolidated subsidiary that is jointly owned by us, WPS, and UPPCO. At March 31, 2014, we had an 86.37% ownership interest, while WPS and UPPCO had an 11.24% and 2.39% ownership interest, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2014, all equity contributions to WPS Investments, LLC were made solely by us.

ACCUMULATED_OTHER_COMPREHENSIV1

ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)	3 Months Ended
	Mar. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]	'
Schedule of changes, net of tax, in accumulated other comprehensive loss	'
	The following tables show the changes, net of tax, to our accumulated other comprehensive loss during the three months ended March 31:
	Three Months Ended March 31, 2014								Accumulated Other
	(Millions)		Cash Flow Hedges			Defined Benefit Plans			Comprehensive Loss
	Beginning balance at December 31, 2013		$	(3.1	)	$	(20.1	)	$	(23.2	)
	Other comprehensive loss before reclassifications		—			(0.1		)	(0.1		)
	Amounts reclassified out of accumulated other comprehensive loss		(0.6		)	0.3			(0.3		)
	Net current period other comprehensive income (loss)		(0.6		)	0.2			(0.4		)
	Ending balance at March 31, 2014		$	(3.7	)	$	(19.9	)	$	(23.6	)
	Three Months Ended March 31, 2013								Accumulated Other
	(Millions)		Cash Flow Hedges			Defined Benefit Plans			Comprehensive Loss
	Beginning balance at December 31, 2012		$	(5.2	)	$	(35.7	)	$	(40.9	)
	Other comprehensive income before reclassifications		0.1			—			0.1
	Amounts reclassified out of accumulated other comprehensive loss		0.9			0.6			1.5
	Net current period other comprehensive income		1			0.6			1.6
	Ending balance at March 31, 2013		$	(4.2	)	$	(35.1	)	$	(39.3	)
Schedule of reclassifications out of accumulated other comprehensive loss	'
	The following table shows the reclassifications out of accumulated other comprehensive loss during the three months ended March 31:
			Amount Reclassified
			Three Months Ended March 31
	(Millions)		2014			2013			Affected Line Item in the Statements of Income
	Losses on cash flow hedges
	Utility commodity derivative contracts		$	—		$	0.2		Operating and maintenance expense (1) (2)
	Nonregulated commodity derivative contracts		—			1.1			Nonregulated revenues (2)
	Interest rate hedges		0.3			0.2			Interest expense
			0.3			1.5			Total before tax
			0.9			0.6			Tax expense
			(0.6		)	0.9			Net of tax
	Defined benefit plans
	Amortization of prior service credits		(0.1		)	(0.1		)	(3)
	Amortization of net actuarial losses		0.7			1.1			(3)
			0.6			1			Total before tax
			0.3			0.4			Tax expense
			0.3			0.6			Net of tax
	Total reclassifications		$	(0.3	)	$	1.5
	(1)	This item relates to changes in the price of natural gas used to support utility operations.
	(2)	We no longer designate commodity contracts as cash flow hedges.
	(3)	These items are included in the computation of net periodic benefit cost. See Note 13, Employee Benefit Plans, for more information.

FAIR_VALUE_Tables

FAIR VALUE (Tables)	3 Months Ended
	Mar. 31, 2014
Fair Value Disclosures [Abstract]	'
Fair value of assets and liabilities measured on a recurring basis, categorized by level within the fair value hierarchy	'
	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, 2014
	(Millions)		Level 1			Level 2			Level 3			Total
	Assets
	Risk Management Assets
	Utility Segments
	Natural gas contracts		$	0.9		$	12.4		$	—		$	13.3
	Financial transmission rights (FTRs)		—			—			0.9			0.9
	Petroleum product contracts		0.1			—			—			0.1
	Coal contracts		—			—			1.8			1.8
	Nonregulated Segments
	Natural gas contracts		20.6			28.8			27.5			76.9
	Electric contracts		88			127.6			21.8			237.4
	Total Risk Management Assets		$	109.6		$	168.8		$	52		$	330.4
	Investment in exchange-traded funds		$	16.2		$	—		$	—		$	16.2
	Liabilities
	Risk Management Liabilities
	Utility Segments
	Natural gas contracts		$	0.2		$	0.2		$	—		$	0.4
	FTRs		—			—			0.2			0.2
	Coal contracts		—			—			1.5			1.5
	Nonregulated Segments
	Natural gas contracts		10.2			20.4			22			52.6
	Electric contracts		112.3			51.9			3.1			167.3
	Total Risk Management Liabilities		$	122.7		$	72.5		$	26.8		$	222
	Contingent consideration related to the acquisition of Compass Energy Services (Compass)		$	—		$	—		$	7.8		$	7.8
			31-Dec-13
	(Millions)		Level 1			Level 2			Level 3			Total
	Assets
	Risk Management Assets
	Utility Segments
	Natural gas contracts		$	2.4		$	7.7		$	—		$	10.1
	FTRs		—			—			2.1			2.1
	Petroleum product contracts		0.1			—			—			0.1
	Coal contracts		—			—			0.2			0.2
	Nonregulated Segments
	Natural gas contracts		16.3			35.2			35.6			87.1
	Electric contracts		65.1			134.9			15.9			215.9
	Total Risk Management Assets		$	83.9		$	177.8		$	53.8		$	315.5
	Investment in exchange-traded funds		$	15.9		$	—		$	—		$	15.9
	Liabilities
	Risk Management Liabilities
	Utility Segments
	Natural gas contracts		$	0.5		$	0.6		$	—		$	1.1
	FTRs		—			—			0.3			0.3
	Coal contracts		—			—			2.7			2.7
	Nonregulated Segments
	Natural gas contracts		14.3			22			25.2			61.5
	Electric contracts		98.8			58.7			3.5			161
	Total Risk Management Liabilities		$	113.6		$	81.3		$	31.7		$	226.6
	Contingent consideration related to the acquisition of Compass		$	—		$	—		$	7.8		$	7.8
Schedule of transfers between the levels of the fair value hierarchy	'
	The following tables show net risk management assets transferred between the levels of the fair value hierarchy:
			Nonregulated Segments — Natural Gas Contracts
			Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
	(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			—
	Transfers into Level 3 from		—			0.9			N/A			—			0.2			N/A
			Nonregulated Segments — Electric Contracts
			Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
	(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			4.4			$	—		N/A			5.5
	Transfers into Level 3 from		—			2.6			N/A			—			—			N/A
Significant unobservable inputs used in the valuation of derivatives categorized in Level 3	'
	The amounts and percentages listed in the table below represent the range of unobservable inputs used in the valuations that individually had a significant impact on the fair value determination and caused a derivative to be classified as Level 3 at March 31, 2014:
			Fair Value (Millions)
			Assets			Liabilities			Valuation Technique		Unobservable Input	Average or Range
	Utility Segments
	FTRs		$	0.9		$	0.2		Market-based		Forward market prices ($/megawatt-month) (1)	$172.92
	Coal contracts		1.8			1.5			Market-based		Forward market prices ($/ton) (2)	$12.11 — $15.25
	Nonregulated Segments
	Natural gas contracts		27.5			22			Market-based		Forward market prices ($/dekatherm) (3)	($2.59) — $3.85
											Probability of default (4)	11.6% — 51.0%
	Electric contracts		21.8			3.1			Market-based		Forward market prices ($/megawatt-hours) (3)	($5.02) — $10.06
											Probability of default (4)	26.00%
											Option volatilities (5)	19.8% — 155.6%
											Monthly curve shaping (6)	-27.00%
	Contingent consideration related to the acquisition of Compass		N/A			7.8			Income-based		Growth rate (7)	(13.2)% - 49.3%
	(1)	Represents forward market prices developed using historical cleared pricing data from MISO.
	(2)	Represents third-party forward market pricing.
	(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)	Based on Moody's one-year counterparty default percentages.
	(5)	Represents the range of volatilities used in the valuation of options. Volatilities are derived from an internal model using volatility curves from third parties.
	(6)	Represents adjustments made to forward market price curves to disaggregate average prices of multiple periods into discrete monthly prices.
	(7)	Represents the range of assumed growth rates of earnings before interest, taxes, and amortization input into the valuation model.
Reconciliation of changes in Level 3 fair value measurements	'
	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, 2014		Nonregulated Segments									Utility Segments
	(Millions)		Natural Gas			Electric			Contingent Consideration			FTRs			Coal Contracts			Total
	Balance at the beginning of the period		$	10.4		$	12.4		$	(7.8	)	$	1.8		$	(2.5	)	$	14.3
	Net realized and unrealized (losses) gains included in earnings		(6.2		)	12.6			—			0.4			—			6.8
	Net unrealized gains recorded as regulatory assets or liabilities		—			—			—			—			2.2			2.2
	Purchases		—			0.7			—			(0.1		)	—			0.6
	Sales		—			(0.7		)	—			—			—			(0.7		)
	Settlements		0.5			(4.5		)	—			(1.4		)	0.6			(4.8		)
	Net transfers into Level 3		0.9			2.6			—			—			—			3.5
	Net transfers out of Level 3		(0.1		)	(4.4		)	—			—			—			(4.5		)
	Balance at the end of the period		$	5.5		$	18.7		$	(7.8	)	$	0.7		$	0.3		$	17.4
	Net unrealized (losses) gains included in earnings related to instruments still held at the end of the period		$	(6.2	)	$	12.6		$	—		$	—		$	—		$	6.4
	Three Months Ended March 31, 2013		Nonregulated Segments						Utility Segments
	(Millions)		Natural Gas			Electric			FTRs			Coal Contracts			Total
	Balance at the beginning of the period		$	3.9		$	(4.3	)	$	2		$	(6.5	)	$	(4.9	)
	Net realized and unrealized (losses) gains included in earnings		(1.5		)	15.1			0.3			—			13.9
	Net unrealized (losses) gains recorded as regulatory assets or liabilities		—			—			(0.2		)	3.1			2.9
	Purchases		—			0.7			—			—			0.7
	Settlements		(0.9		)	0.1			(1.2		)	(1.2		)	(3.2		)
	Net transfers into Level 3		0.2			—			—			—			0.2
	Net transfers out of Level 3		—			(5.5		)	—			—			(5.5		)
	Balance at the end of the period		$	1.7		$	6.1		$	0.9		$	(4.6	)	$	4.1
	Net unrealized (losses) gains included in earnings related to instruments still held at the end of the period		$	(1.5	)	$	15.1		$	—		$	—		$	13.6
Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value	'
	The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:
			March 31, 2014						December 31, 2013
	(Millions)		Carrying Amount			Fair Value			Carrying Amount			Fair Value
	Long-term debt		$	3,056.20		$	3,076.40		$	3,056.20		$	3,031.60
	Preferred stock of subsidiary		51.1			57.3			51.1			61.2

SEGMENTS_OF_BUSINESS_Tables

SEGMENTS OF BUSINESS (Tables)	3 Months Ended
	Mar. 31, 2014
Segment Reporting [Abstract]	'
Schedule of information related to reportable segments	'
	The tables below present information related to our reportable segments:
		Regulated Operations											Nonutility and Nonregulated Operations
	(Millions)	Natural Gas			Electric			Electric		Total			IES			Holding			Reconciling			Integrys
		Utility			Utility			Transmission		Regulated						Company			Eliminations			Energy Group
								Investment		Operations						and Other						Consolidated
	Three Months Ended
	March 31, 2014
	External revenues	$	1,267.50		$	349.2		$	—	$	1,616.70		$	1,289.60		$	18.6		$	—		$	2,924.90
	Intersegment revenues	4.5			—			—		4.5			2.6			0.4			(7.5		)	—
	Depreciation and amortization expense	36.4			25.6			—		62			2.9			6.5			(0.1		)	71.3
	Earnings from equity method investments	—			—			22.5		22.5			0.1			0.3			—			22.9
	Miscellaneous income	0.3			3.5			—		3.8			0.3			5.4			(3.5		)	6
	Interest expense	13.4			11.7			—		25.1			0.5			17			(3.5		)	39.1
	Provision (benefit) for income taxes	66.7			18.1			8.8		93.6			5.9			(9.7		)	—			89.8
	Net income (loss) from continuing operations	99.2			31.8			13.7		144.7			10.9			(2.4		)	—			153.2
	Discontinued operations	—			—			—		—			(0.1		)	—			—			(0.1		)
	Preferred stock dividends of subsidiary	(0.1		)	(0.7		)	—		(0.8		)	—			—			—			(0.8		)
	Noncontrolling interest in subsidiaries	—			—			—		—			—			0.1			—			0.1
	Net income (loss) attributed to common shareholders	99.1			31.1			13.7		143.9			10.8			(2.3		)	—			152.4
		Regulated Operations											Nonutility and Nonregulated Operations
	(Millions)	Natural Gas			Electric			Electric		Total			IES			Holding			Reconciling			Integrys
		Utility			Utility			Transmission		Regulated						Company			Eliminations			Energy Group
								Investment		Operations						and Other						Consolidated
	Three Months Ended
	31-Mar-13
	External revenues	$	792		$	331.8		$	—	$	1,123.80		$	545.4		$	9		$	—		$	1,678.20
	Intersegment revenues	1.9			—			—		1.9			0.3			0.4			(2.6		)	—
	Depreciation and amortization expense	32.2			21.5			—		53.7			2.7			4.6			(0.1		)	60.9
	Earnings from equity method investments	—			—			21.7		21.7			0.2			0.4			—			22.3
	Miscellaneous income	0.2			1.6			—		1.8			0.4			7.2			(3.7		)	5.7
	Interest expense	12.7			9.1			—		21.8			0.5			10.7			(3.7		)	29.3
	Provision (benefit) for income taxes	63.3			16.1			8.3		87.7			27.3			(5.4		)	—			109.6
	Net income (loss) from continuing operations	89.8			29.3			13.4		132.5			51.3			(1.6		)	—			182.2
	Discontinued operations	—			—			—		—			0.1			6			—			6.1
	Preferred stock dividends of subsidiary	(0.1		)	(0.7		)	—		(0.8		)	—			—			—			(0.8		)
	Net income attributed to common shareholders	89.7			28.6			13.4		131.7			51.4			4.4			—			187.5

CASH_AND_CASH_EQUIVALENTS_Deta

CASH AND CASH EQUIVALENTS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Significant noncash transactions	'	'
Construction costs funded through accounts payable	$92.30	$59.80
Equity issued for employee stock ownership plan	1.7	2.7
Equity issued for stock-based compensation plans	0	16
Equity issued for reinvested dividends	$0	$3

RISK_MANAGEMENT_ACTIVITIES_RIS

RISK MANAGEMENT ACTIVITIES - RISK MANAGEMENT ASSETS AND LIABILITIES (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative assets and liabilities from risk management activities	'	'
Assets from risk management activities	$269.90	$239.50
Assets from risk management activities	60.3	75.4
Risk Management Assets	330.4	315.5
Liabilities from risk management activities	175.8	163.8
Liabilities from risk management activities	46.2	62.8
Risk Management Liabilities	222	226.6
Non-hedge derivatives	'	'
Derivative assets and liabilities from risk management activities	'	'
Assets from risk management activities	270.1	240.1
Assets from risk management activities	60.3	75.4
Risk Management Assets	330.4	315.5
Liabilities from risk management activities	175.8	163.8
Liabilities from risk management activities	46.2	62.8
Risk Management Liabilities	222	226.6
Non-hedge derivatives | Utility segments | Natural gas contracts	'	'
Derivative assets and liabilities from risk management activities	'	'
Assets from risk management activities	12.3	8.3
Assets from risk management activities	1	1.8
Liabilities from risk management activities	0.3	1
Liabilities from risk management activities	0.1	0.1
Non-hedge derivatives | Utility segments | FTRs	'	'
Derivative assets and liabilities from risk management activities	'	'
Assets from risk management activities	0.9	2.1
Liabilities from risk management activities	0.2	0.3
Non-hedge derivatives | Utility segments | FTRs | UPPCO	'	'
Disclosures related to the disposal	'	'
Current risk management assets classified as held for sale	0.2	0.6
Non-hedge derivatives | Utility segments | Petroleum product contracts	'	'
Derivative assets and liabilities from risk management activities	'	'
Assets from risk management activities	0.1	0.1
Liabilities from risk management activities	0	0
Non-hedge derivatives | Utility segments | Coal contracts	'	'
Derivative assets and liabilities from risk management activities	'	'
Assets from risk management activities	0	0
Assets from risk management activities	1.8	0.2
Liabilities from risk management activities	1.1	1.9
Liabilities from risk management activities	0.4	0.8
Non-hedge derivatives | Nonregulated segments | Natural gas contracts	'	'
Derivative assets and liabilities from risk management activities	'	'
Assets from risk management activities	56	57.6
Assets from risk management activities	20.9	29.5
Liabilities from risk management activities	41.7	42.9
Liabilities from risk management activities	10.9	18.6
Non-hedge derivatives | Nonregulated segments | Electric contracts	'	'
Derivative assets and liabilities from risk management activities	'	'
Assets from risk management activities	200.8	172
Assets from risk management activities	36.6	43.9
Liabilities from risk management activities	132.5	117.7
Liabilities from risk management activities	$34.80	$43.30

RISK_MANAGEMENT_ACTIVITIES_NET

RISK MANAGEMENT ACTIVITIES - NETTING ARRANGEMENTS (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Assets	'	'
Derivative assets subject to master netting or similar arrangements, gross amount	$328.30	$314.20
Potential effects of netting, including cash collateral	193.6	180.2
Derivative assets subject to master netting or similar arrangements, net amount	134.7	134
Derivative assets not subject to master netting or similar arrangements	2.1	1.3
Risk Management Assets	330.4	315.5
Total Risk Management Assets, Net Amount	136.8	135.3
Liabilities	'	'
Derivative liabilities subject to master netting or similar arrangements, gross amount	220.4	223.5
Potential effects of netting, including cash collateral	193.6	179.5
Derivative liabilities subject to master netting or similar arrangements, net amount	26.8	44
Derivative liabilities not subject to master netting or similar arrangement	1.6	3.1
Risk Management Liabilities	222	226.6
Total Risk Management Liabilities, Net Amount	28.4	47.1
Utility segments	'	'
Assets	'	'
Derivative assets subject to master netting or similar arrangements, gross amount	14.3	12.3
Potential effects of netting, including cash collateral	0.6	2.1
Derivative assets subject to master netting or similar arrangements, net amount	13.7	10.2
Liabilities	'	'
Derivative liabilities subject to master netting or similar arrangements, gross amount	0.6	1.4
Potential effects of netting, including cash collateral	0.6	1.4
Derivative liabilities subject to master netting or similar arrangements, net amount	0	0
Nonregulated segments	'	'
Assets	'	'
Derivative assets subject to master netting or similar arrangements, gross amount	314	301.9
Potential effects of netting, including cash collateral	193	178.1
Derivative assets subject to master netting or similar arrangements, net amount	121	123.8
Liabilities	'	'
Derivative liabilities subject to master netting or similar arrangements, gross amount	219.8	222.1
Potential effects of netting, including cash collateral	193	178.1
Derivative liabilities subject to master netting or similar arrangements, net amount	$26.80	$44

RISK_MANAGEMENT_ACTIVITIES_CAS

RISK MANAGEMENT ACTIVITIES - CASH COLLATERAL AND CREDIT-RISK RELATED CONTINGENT FEATURES (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Cash collateral	'	'
Cash collateral provided to others, related to contracts under master netting or similar arrangements	$74.60	$37.60
Cash collateral provided to others, other	1.1	1.1
Cash collateral received from others related to contracts under master netting or similar arrangements	1.5	0.7
UPPCO	'	'
Disclosures related to the disposal	'	'
Cash collateral provided to others classified as held for sale	1.3	1.3
Utility segments	'	'
Credit-risk related contingent features	'	'
Aggregate fair value of derivative instruments with credit risk-related contingent features that were in a liability position	0.2	0.6
Collateral that would have been required	0	0
Nonregulated segments	'	'
Credit-risk related contingent features	'	'
Aggregate fair value of derivative instruments with credit risk-related contingent features that were in a liability position	58.4	76.7
Collateral that would have been required	199.7	197.6
Collateral already satisfied, letters of credit	20	4.5
Collateral remaining	$179.70	$193.10

RISK_MANAGEMENT_ACTIVITIES_UTI

RISK MANAGEMENT ACTIVITIES - UTILITY SEGMENTS, NOTIONAL VOLUMES (Details) (Non-hedge derivatives, Utility segments)	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
	Btu	Btu
Natural gas contracts | Purchases	'	'
Risk management activities	'	'
Notional volume of outstanding derivative contracts (therms or kwh)	2,438,800,000	3,124,800,000
Natural gas contracts | Sales	'	'
Risk management activities	'	'
Notional volume of outstanding derivative contracts (therms or kwh)	2,100,000	29,300,000
FTRs | Other transactions	'	'
Risk management activities	'	'
Notional volume of outstanding derivative contracts (therms or kwh)	1,448,700,000	3,633,100,000
Petroleum product contracts | Purchases	'	'
Risk management activities	'	'
Notional volume of outstanding derivative contracts (barrels)	113,000	102,811
Petroleum product contracts | Sales	'	'
Risk management activities	'	'
Notional volume of outstanding derivative contracts (barrels)	20,000	14,000
Coal contracts | Purchases	'	'
Risk management activities	'	'
Notional volume of outstanding non-hedge derivative contracts (tons)	4,300,000	4,800,000
Coal contracts | Sales	'	'
Risk management activities	'	'
Notional volume of outstanding non-hedge derivative contracts (tons)	0	0

RISK_MANAGEMENT_ACTIVITIES_UTI1

RISK MANAGEMENT ACTIVITIES - UTILITY SEGMENTS, UNREALIZED GAINS AND LOSSES (Details) (Utility segments, USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Natural gas contracts | Balance Sheet - Regulatory assets (current)	'	'
Risk management activities	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	$0.90	$13
Natural gas contracts | Balance Sheet - Regulatory assets (long-term)	'	'
Risk management activities	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	-0.2	0.8
Natural gas contracts | Balance Sheet - Regulatory liabilities (current)	'	'
Risk management activities	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	3.4	5.9
Natural gas contracts | Balance Sheet - Regulatory liabilities (long-term)	'	'
Risk management activities	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	-0.4	0.8
Natural gas contracts | Income Statement - Operating and maintenance expense	'	'
Risk management activities	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	0.2	0.2
FTRs | Balance Sheet - Regulatory assets (current)	'	'
Risk management activities	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	0.2	0.2
FTRs | Balance Sheet - Regulatory liabilities (current)	'	'
Risk management activities	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	-0.2	-0.4
Coal contracts | Balance Sheet - Regulatory assets (current)	'	'
Risk management activities	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	0.2	1.9
Coal contracts | Balance Sheet - Regulatory assets (long-term)	'	'
Risk management activities	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	0.4	2.3
Coal contracts | Balance Sheet - Regulatory liabilities (current)	'	'
Risk management activities	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	0	-0.2
Coal contracts | Balance Sheet - Regulatory liabilities (long-term)	'	'
Risk management activities	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	$1.60	($2.20)

RISK_MANAGEMENT_ACTIVITIES_NON

RISK MANAGEMENT ACTIVITIES - NONREGULATED SEGMENTS, NOTIONAL VOLUMES (Details) (Non-hedge derivatives, Nonregulated segments)	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
	Btu	Btu
Natural gas contracts | Purchases	'	'
Risk management activities	'	'
Notional volume of outstanding derivative contracts (therms or kwh)	919,200,000	1,199,900,000
Natural gas contracts | Sales	'	'
Risk management activities	'	'
Notional volume of outstanding derivative contracts (therms or kwh)	774,300,000	1,065,400,000
Electric contracts | Purchases	'	'
Risk management activities	'	'
Notional volume of outstanding derivative contracts (therms or kwh)	40,473,700,000	49,186,300,000
Electric contracts | Sales	'	'
Risk management activities	'	'
Notional volume of outstanding derivative contracts (therms or kwh)	25,245,000,000	30,813,800,000

RISK_MANAGEMENT_ACTIVITIES_NON1

RISK MANAGEMENT ACTIVITIES - NONREGULATED SEGMENTS, GAINS AND LOSSES (Details) (Nonregulated segments, USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Risk management activities	'	'
Gains (losses) recorded related to non-hedge derivatives (total)	$157	$64.70
Natural gas contracts | Nonregulated revenue	'	'
Risk management activities	'	'
Gains (losses) recorded related to non-hedge derivatives	-36.9	3.4
Natural gas contracts | Nonregulated cost of sales	'	'
Risk management activities	'	'
Gains (losses) recorded related to non-hedge derivatives	33	-1.6
Natural gas contracts | Nonregulated revenue (reclassified from accumulated OCI)	'	'
Risk management activities	'	'
Gains (losses) recorded related to non-hedge derivatives (prior cash flow hedge)	0	-0.1
Electric contracts | Nonregulated revenue	'	'
Risk management activities	'	'
Gains (losses) recorded related to non-hedge derivatives	160.3	64
Electric contracts | Nonregulated cost of sales	'	'
Risk management activities	'	'
Gains (losses) recorded related to non-hedge derivatives	0.6	0
Electric contracts | Nonregulated revenue (reclassified from accumulated OCI)	'	'
Risk management activities	'	'
Gains (losses) recorded related to non-hedge derivatives (prior cash flow hedge)	$0	($1)

ACQUISITIONS_Details

ACQUISITIONS (Details) (USD $)	3 Months Ended			1 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014
			Alliant Energy Corporation's natural gas distribution business in southeast Minnesota	Fox Energy Company LLC	Fox Energy Company LLC
			MERC	WPS	WPS
				MW
Acquisitions	'	'	'	'	'
Estimated purchase price	'	'	$11	'	'
Purchase price	0	391.6	'	391.6	'
Capacity of electric generating facility	'	'	'	593	'
Assets acquired	'	'	'	'	'
Inventories	'	'	'	3	'
Other current assets	'	'	'	0.4	'
Property, plant, and equipment	'	'	'	374.4	'
Other long-term assets	'	'	'	15.6	'
Total assets acquired	'	'	'	393.4	'
Liabilities assumed	'	'	'	'	'
Accounts payable	'	'	'	1.8	'
Total liabilities assumed	'	'	'	1.8	'
Contracted capacity from power purchase agreement	'	'	'	500	'
Termination of tolling agreement with Fox Energy Company LLC	$0	($50)	'	$50	'
Amortization period of regulatory asset	'	'	'	'	'9 years

DISPOSITIONS_DISPOSITIONS_EXCL

DISPOSITIONS - DISPOSITIONS EXCLUDING DISCONTINUED OPERATIONS (Details) (Electric Utility, UPPCO, USD $)	1 Months Ended
In Millions, unless otherwise specified	Jan. 31, 2014	Mar. 31, 2014	Dec. 31, 2013
Disclosures related to the disposal	'	'	'
Expected proceeds from sale	$298.80	'	'
Intercompany payables included in sale	'	2	1.6
Assets and liabilities classified as held for sale on balance sheets	'	'	'
Current assets	'	27.2	26.5
Property, plant, and equipment, net of accumulated depreciation of $90.2 and $88.9, respectively	'	193.2	193.8
Accumulated depreciation	'	90.2	88.9
Other long-term assets	'	65.6	51.6
Total assets	'	286	271.9
Current liabilities	'	12	16.7
Long-term liabilities	'	24.7	32.4
Total liabilities	'	$36.70	$49.10
Minimum	'	'	'
Disclosures related to the disposal	'	'	'
Transition period for administrative and operational services	'18 months	'	'
Maximum	'	'	'
Disclosures related to the disposal	'	'	'
Transition period for administrative and operational services	'30 months	'	'

DISPOSITIONS_DISCONTINUED_OPER

DISPOSITIONS - DISCONTINUED OPERATIONS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Discontinued operations recorded in income statements	'	'	'
Discontinued operations, net of tax	($0.10)	$6.10	'
Holding Company and Other	'	'	'
Discontinued operations recorded in income statements	'	'	'
Discontinued operations, net of tax	'	6	'
Integrys Energy Services | Combined Locks Energy Center	'	'	'
Assets classified as held for sale on balance sheets	'	'	'
Total assets	0.7	'	0.7
Discontinued operations recorded in income statements	'	'	'
Discontinued operations, net of tax	-0.1	-0.1	'
Integrys Energy Services | WPS Empire State, Inc | WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC	'	'	'
Discontinued operations recorded in income statements	'	'	'
Discontinued operations, net of tax	'	$0.20	'

INVESTMENT_IN_ATC_ROLL_FORWARD

INVESTMENT IN ATC - ROLL FORWARD (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Changes in equity method investments	'	'
Equity method investments balance at beginning of period	$540.90	'
Add: Earnings from equity method investment	22.9	22.3
Add: Capital contributions	5.1	1.7
Equity method investments balance at end of period	548.1	'
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	508.4	476.6
Add: Earnings from equity method investment	22.5	21.7
Add: Capital contributions	5.1	1.7
Less: Dividends received	18.4	17.3
Equity method investments balance at end of period	$517.60	$482.70

INVESTMENT_IN_ATC_INCOME_STATE

INVESTMENT IN ATC - INCOME STATEMENT AND BALANCE SHEET (Details) (ATC, USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
ATC	'	'	'
Income statement data	'	'	'
Revenues	$163.30	$151.80	'
Operating expenses	78.6	69.8	'
Other expense	21.6	21.5	'
Net income	63.1	60.5	'
Balance sheet data	'	'	'
Current assets	79.2	'	80.7
Noncurrent assets	3,563.90	'	3,509.50
Total assets	3,643.10	'	3,590.20
Current liabilities	301.4	'	381.5
Long-term debt	1,650	'	1,550
Other noncurrent liabilities	131.2	'	126.1
Shareholders' equity	1,560.50	'	1,532.60
Total liabilities and shareholders' equity	$3,643.10	'	$3,590.20

INVENTORIES_Details

INVENTORIES (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Temporary LIFO liquidation credit [Line Items]	'	'
Temporary LIFO liquidation credit	$150.90	$0
PGL and NSG	'	'
Temporary LIFO liquidation credit [Line Items]	'	'
Temporary LIFO liquidation credit	$150.90	'

GOODWILL_AND_OTHER_INTANGIBLE_2

GOODWILL AND OTHER INTANGIBLE ASSETS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'	'	'
Changes in the carrying amount of goodwill	$0	$0	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	73.1	'	71.9
Accumulated amortization of intangible assets	-25.6	'	-23.5
Amortized intangible assets, net	47.5	'	48.4
Unamortized intangible assets	'	'	'
Total intangible assets, gross	83.3	'	82.1
Total intangible assets, net	57.7	'	58.6
Amortization expense for the next five years	'	'	'
Future amortization expense period	'5 years	'	'
Nonregulated cost of sales	'	'	'
Amortized intangible assets	'	'	'
Amortization expense	1	0.4	'
Amortization expense for the next five years	'	'	'
Amortization expense, 2014	3.4	'	'
Amortization expense, 2015	2	'	'
Amortization expense, 2016	1.1	'	'
Amortization expense, 2017	0.9	'	'
Amortization expense, 2018	0.8	'	'
Depreciation and amortization	'	'	'
Amortized intangible assets	'	'	'
Amortization expense	1.1	0.5	'
Amortization expense for the next five years	'	'	'
Amortization expense, 2014	4.3	'	'
Amortization expense, 2015	4.2	'	'
Amortization expense, 2016	4	'	'
Amortization expense, 2017	3.9	'	'
Amortization expense, 2018	3.8	'	'
Trade name | MGU	'	'	'
Unamortized intangible assets	'	'	'
Unamortized intangible asset, carrying amount	5.2	'	5.2
Trade name | Trillium	'	'	'
Unamortized intangible assets	'	'	'
Unamortized intangible asset, carrying amount	3.5	'	3.5
Trade name | Pinnacle	'	'	'
Unamortized intangible assets	'	'	'
Unamortized intangible asset, carrying amount	1.5	'	1.5
Customer-related	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	26.8	'	26.8
Accumulated amortization of intangible assets	-16.1	'	-15.7
Amortized intangible assets, net	10.7	'	11.1
Weighted-average amortization period	'11 years	'	'
Contractual service agreements	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	15.6	'	15.6
Accumulated amortization of intangible assets	-2.4	'	-1.8
Amortized intangible assets, net	13.2	'	13.8
Weighted-average amortization period	'6 years	'	'
Renewable energy credits	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	9.6	'	8.4
Accumulated amortization of intangible assets	0	'	0
Amortized intangible assets, net	9.6	'	8.4
Compressed natural gas fueling contract assets	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	5.6	'	5.6
Accumulated amortization of intangible assets	-2.9	'	-2.7
Amortized intangible assets, net	2.7	'	2.9
Weighted-average amortization period	'7 years	'	'
Customer-owned equipment modifications	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	4	'	4
Accumulated amortization of intangible assets	-0.9	'	-0.9
Amortized intangible assets, net	3.1	'	3.1
Weighted-average amortization period	'10 years	'	'
Natural gas and electric contract assets	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	3.9	'	3.9
Accumulated amortization of intangible assets	-1.2	'	-0.5
Amortized intangible assets, net	2.7	'	3.4
Weighted-average amortization period	'4 years	'	'
Nonregulated easements	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	3.7	'	3.7
Accumulated amortization of intangible assets	-1.2	'	-1.1
Amortized intangible assets, net	2.5	'	2.6
Weighted-average amortization period	'10 years	'	'
Patents/intellectual property	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	3.4	'	3.4
Accumulated amortization of intangible assets	-0.6	'	-0.5
Amortized intangible assets, net	2.8	'	2.9
Weighted-average amortization period	'8 years	'	'
Other amortized intangible assets	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	0.5	'	0.5
Accumulated amortization of intangible assets	-0.3	'	-0.3
Amortized intangible assets, net	$0.20	'	$0.20

SHORTTERM_DEBT_AND_LINES_OF_CR2

SHORT-TERM DEBT AND LINES OF CREDIT SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Short-term borrowings	'	'	'
Short-term borrowings outstanding	$321.90	'	$326
Commercial paper	'	'	'
Short-term borrowings	'	'	'
Short-term borrowings outstanding	321.9	'	326
Average interest rate (as a percent)	0.23%	'	0.22%
Average amount of short-term borrowings outstanding	$247.10	$400.70	'

SHORTTERM_DEBT_AND_LINES_OF_CR3

SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Short-term borrowings	'	'
Total short-term credit capacity	$1,610	$1,610
Letters of credit issued inside credit facilities	70.6	52.4
Short-term borrowings outstanding	321.9	326
Available capacity under existing agreements	1,217.50	1,231.60
Revolving credit facility maturing on May 17, 2014 | Integrys Energy Group, Inc.	'	'
Short-term borrowings	'	'
Total short-term credit capacity	275	275
Revolving credit facility maturing on May 17, 2014 | WPS	'	'
Short-term borrowings	'	'
Total short-term credit capacity	135	135
Revolving credit facility maturing on May 17, 2016 | Integrys Energy Group, Inc.	'	'
Short-term borrowings	'	'
Total short-term credit capacity	200	200
Revolving credit facility maturing on June 13, 2017 | Integrys Energy Group, Inc.	'	'
Short-term borrowings	'	'
Total short-term credit capacity	635	635
Revolving credit facility maturing on June 13, 2017 | WPS	'	'
Short-term borrowings	'	'
Total short-term credit capacity	115	115
Revolving credit facility maturing on June 13, 2017 | PGL	'	'
Short-term borrowings	'	'
Total short-term credit capacity	250	250
Commercial paper	'	'
Short-term borrowings	'	'
Short-term borrowings outstanding	$321.90	$326

INCOME_TAXES_Details

INCOME TAXES (Details)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Income Tax Disclosure [Abstract]	'	'
Effective tax rate (as a percent)	37.00%	37.60%
Federal statutory tax rate (as a percent)	35.00%	35.00%

COMMITMENTS_AND_CONTINGENCIES_1

COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS AND PURCHASE ORDER COMMITMENTS (Details) (USD $)	Mar. 31, 2014
In Millions, unless otherwise specified
Minimum future commitments for purchase obligations	'
Total Amounts Committed	$2,407.20
2014	611.4
2015	408.8
2016	263.1
2017	191.1
2018	130.6
Later Years	802.2
Purchase orders	1,163.30
Natural gas utility supply and transportation | Regulated operations | Natural Gas Utility	'
Minimum future commitments for purchase obligations	'
Total Amounts Committed	793.7
2014	128.2
2015	169.7
2016	158.5
2017	122.6
2018	71.7
Later Years	143
Purchased power | Regulated operations | Electric Utility	'
Minimum future commitments for purchase obligations	'
Total Amounts Committed	918
2014	59.8
2015	49.4
2016	42.8
2017	53.2
2018	54
Later Years	658.8
Coal supply and transportation | Regulated operations | Electric Utility	'
Minimum future commitments for purchase obligations	'
Total Amounts Committed	94.6
2014	47
2015	28.5
2016	9.9
2017	5.9
2018	3.3
Later Years	0
Nonregulated electricity and natural gas supply | Nonutility and nonregulated operations | Integrys Energy Services	'
Minimum future commitments for purchase obligations	'
Total Amounts Committed	600.9
2014	376.4
2015	161.2
2016	51.9
2017	9.4
2018	1.6
Later Years	0.4
UPPCO | Regulated operations | Electric Utility	'
Minimum future commitments for purchase obligations	'
Purchase orders	12.2
UPPCO | Purchased power | Regulated operations | Electric Utility	'
Minimum future commitments for purchase obligations	'
Total Amounts Committed	$8.20

COMMITMENTS_AND_CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) (USD $)	Mar. 31, 2014	Mar. 31, 2013	Jun. 30, 2013	Mar. 31, 2014
In Millions, unless otherwise specified	Manufactured gas plant remediation	WPS	WPS	WPS
	Natural Gas Utility	Weston and Pulliam plants	Columbia and Edgewater jointly-owned plants	Mercury emission
	site	Electric Utility	Electric Utility	Electric Utility
				MW
Air Permitting Violation Claims	'	'	'	'
Beneficial environmental project amount	'	$6	$1.30	'
Civil penalty and/or legal fees	'	1.2	0.4	'
Mercury and Interstate Air Quality Rules	'	'	'	'
Percentage mercury reduction required by the State of Wisconsin's mercury rule through 2014	'	'	'	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 by 2015, required by the State of Wisconsin's mercury rule, for electric generating units above 150 MW	'	'	'	90.00%
Level of electric generating units above which a reduction in mercury emissions is required by the Best Available Control Technology rule (in MW)	'	'	'	25
Highest level of electric generating units for which a reduction in mercury emissions is required by the Best Available Control Technology rule (in MW)	'	'	'	150
Estimated capital cost to achieve required emission reduction	'	'	'	8
Manufactured Gas Plant Remediation	'	'	'	'
Number of environmental remediation sites	53	'	'	'
Number of environmental remediation sites transferred to the EPA Superfund Alternative Sites Program	20	'	'	'
Liabilities estimated and accrued for future undiscounted investigation and cleanup costs for all sites	588.2	'	'	'
Cash expenditures for environmental remediation not yet recovered in rates	34.1	'	'	'
Regulatory assets recorded for cash and estimated future remediation expenditures, net of insurance recoveries received	$622.30	'	'	'

GUARANTEES_Details

GUARANTEES (Details) (USD $)	Mar. 31, 2014
In Millions, unless otherwise specified
Guarantees	'
Total guarantees	$843
Guarantees expiring in less than 1 year	513.9
Guarantees expiring within 1 to 3 years	35
Guarantees with expiration over 3 years	294.1
Integrys Energy Services | Texas Retail Electric Marketing Business	'
Guarantees	'
Total guarantees	10
Integrys Energy Services | Sale of Stoneman generation facility	'
Guarantees	'
Total guarantees	1.8
UPPCO	'
Guarantees	'
Total guarantees	3.4
Guarantees supporting commodity transactions	'
Guarantees	'
Total guarantees	684.5
Guarantees expiring in less than 1 year	412.6
Guarantees expiring within 1 to 3 years	31.7
Guarantees with expiration over 3 years	240.2
Guarantees supporting commodity transactions | Integrys Energy Services	'
Guarantees	'
Total guarantees	497.7
Guarantees supporting commodity transactions | ITF	'
Guarantees	'
Total guarantees	0.2
Guarantees supporting commodity transactions | MERC	'
Guarantees	'
Total guarantees	126.7
Guarantees supporting commodity transactions | IBS	'
Guarantees	'
Total guarantees	5
Guarantees supporting commodity transactions | MGU	'
Guarantees	'
Total guarantees	52.9
Guarantees supporting commodity transactions | UPPCO	'
Guarantees	'
Total guarantees	2
Standby letters of credit	'
Guarantees	'
Total guarantees	74.1
Guarantees expiring in less than 1 year	70.7
Guarantees expiring within 1 to 3 years	3.3
Guarantees with expiration over 3 years	0.1
Standby letters of credit | Integrys Energy Services	'
Guarantees	'
Total guarantees	72.1
Standby letters of credit | ITF, MERC, MGU, NSG, PGL, UPPCO, and WPS	'
Guarantees	'
Total guarantees	2
Surety bonds	'
Guarantees	'
Total guarantees	29.1
Guarantees expiring in less than 1 year	29.1
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	0
Other guarantees	'
Guarantees	'
Total guarantees	55.3
Guarantees expiring in less than 1 year	1.5
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	53.8
Other guarantees | Integrys Energy Services	'
Guarantees	'
Total guarantees	35
Other guarantees | ITF	'
Guarantees	'
Total guarantees	2.4
Indemnification and workers' compensation coverage	'
Guarantees	'
Total guarantees	$6.10

EMPLOYEE_BENEFIT_PLANS_Details

EMPLOYEE BENEFIT PLANS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Pension Benefits	'	'
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)	'	'
Service cost	$6.60	$7.50
Interest cost	19.7	17.8
Expected return on plan assets	-28.9	-26.6
Amortization of prior service cost (credit)	0.2	1
Amortization of net actuarial loss	8.4	13.5
Net periodic benefit cost	6	13.2
Contributions to the plans	68.6	'
Expected contributions to the plans during the remainder of fiscal year	3.7	'
Other Postretirement Benefits	'	'
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)	'	'
Service cost	5.9	6.5
Interest cost	7.1	6.3
Expected return on plan assets	-8.8	-7.7
Amortization of prior service cost (credit)	-1.3	-0.6
Amortization of net actuarial loss	0.7	2
Net periodic benefit cost	3.6	6.5
Expected contributions to the plans during the remainder of fiscal year	$11.80	'

STOCKBASED_COMPENSATION_STOCKB

STOCK-BASED COMPENSATION – STOCK-BASED COMPENSATION EXPENSE (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Information related to share based awards	'	'
Total stock-based compensation expense	$4.10	$5.70
Deferred income tax benefit	1.6	2.3
Stock-based compensation cost capitalized	0	0
Stock options	'	'
Information related to share based awards	'	'
Total stock-based compensation expense	0.3	0.4
Performance stock rights	'	'
Information related to share based awards	'	'
Total stock-based compensation expense	0.5	2.2
Restricted Share Units	'	'
Information related to share based awards	'	'
Total stock-based compensation expense	3.1	2.8
Nonemployee director deferred stock units	'	'
Information related to share based awards	'	'
Total stock-based compensation expense	$0.20	$0.30

STOCKBASED_COMPENSATION_STOCK_

STOCK-BASED COMPENSATION – STOCK OPTIONS (Details) (Stock options, USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Stock options	'	'
Weighted-average fair values along with the assumptions incorporated into the valuation model	'	'
Period of historical volatility used to estimate expected volatility	'10 years	'
Expected term	'8 years	'
Risk-free interest rate, minimum (as a percent)	0.12%	'
Risk-free interest rate, maximum (as a percent)	2.88%	'
Expected dividend yield (as a percent)	5.28%	'
Expected volatility (as a percent)	18.00%	'
Weighted-average fair value per stock option (in dollars per share)	$6.70	$6.03
Stock Options	'	'
Outstanding, at the beginning of the period (in shares)	1,550,374	'
Granted (in shares)	264,332	'
Exercised (in shares)	-11,504	'
Outstanding, at the end of the period (in shares)	1,803,202	'
Exercisable at the end of the period (in shares)	1,114,027	'
Weighted-Average Exercise Price Per Share	'	'
Outstanding at the beginning of the period (in dollars per share)	$50.93	'
Granted (in dollars per share)	$55.23	'
Exercised (in dollars per share)	$45.45	'
Outstanding at the end of the period (in dollars per share)	$51.60	'
Exercisable at the end of the period (in dollars per share)	$49.75	'
Weighted-Average Remaining Contractual Life (in Years)	'	'
Outstanding at the end of the period	'6 years 7 months	'
Exercisable at the end of period	'5 years 1 month	'
Aggregate Intrinsic Value	'	'
Outstanding at the end of the period (in dollars)	$14.50	'
Exercisable at the end of the period (in dollars)	11	'
Options exercised (in dollars)	'	1.9
Additional disclosures	'	'
Compensation cost not yet recognized	$2.50	'
Weighted-average period over which compensation cost is to be recognized	'2 years	'

STOCKBASED_COMPENSATION_PERFOR

STOCK-BASED COMPENSATION – PERFORMANCE STOCK RIGHTS (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Performance stock rights	'	'
Assumptions incorporated into the valuation models	'	'
Risk-free interest rate, minimum (as a percent)	0.34%	'
Risk-free interest rate, maximum (as a percent)	0.57%	'
Expected volatility, minimum (as a percent)	15.00%	'
Expected volatility, maximum (as a percent)	22.00%	'
Additional disclosures	'	'
Shares distributed	0	'
Total intrinsic value of shares distributed during the period	'	$8.80
Tax benefit realized from the distribution of shares	'	3.6
Compensation cost not yet recognized	$5.20	'
Weighted-average period over which compensation cost is to be recognized	'1 year 7 months	'
Performance stock rights | Minimum	'	'
Assumptions incorporated into the valuation models	'	'
Period of historical volatility used to estimate expected volatility	'2 years	'
Expected dividend yield (as a percent)	5.28%	'
Performance stock rights | Maximum	'	'
Assumptions incorporated into the valuation models	'	'
Period of historical volatility used to estimate expected volatility	'3 years	'
Expected dividend yield (as a percent)	5.33%	'
Performance Stock Rights Accounted For As Equity Awards	'	'
Performance Stock Rights	'	'
Outstanding at the beginning of the period (in shares)	85,749	'
Granted (in shares)	21,146	'
Adjustment for shares not distributed	-45,748	'
Outstanding at the end of period (in shares)	61,147	'
Weighted-Average Fair Value	'	'
Outstanding at the beginning of the period (in dollars per share)	$46.62	'
Granted (in dollars per share)	$44.28	$48.50
Adjustment for shares not distributed (in dollars per shares)	$43.29	'
Outstanding at the end of the period (in dollars per share)	$48.31	'
Performance Stock Rights Accounted For As Liability Awards	'	'
Performance Stock Rights	'	'
Outstanding at the beginning of the period (in shares)	198,904	'
Granted (in shares)	84,529	'
Adjustment for shares not distributed	-39,001	'
Outstanding at the end of period (in shares)	244,432	'
Weighted-Average Fair Value	'	'
Outstanding at the end of the period, fair value as of the reporting date (in dollars per share)	$38.73	'

STOCKBASED_COMPENSATION_RESTRI

STOCK-BASED COMPENSATION – RESTRICTED SHARE UNITS (Details) (Restricted Share Units, USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Restricted Share Units	'	'
Restricted Share Unit Awards	'	'
Outstanding at the beginning of the period (in shares)	511,301	'
Granted (in shares)	214,953	'
Dividend equivalents (in shares)	6,169	'
Vested and released (in shares)	-204,322	'
Forfeited (in shares)	-781	'
Outstanding at the end of period (in shares)	527,320	'
Weighted-Average Grant Date Fair Value	'	'
Outstanding at the beginning of the period (in dollars per share)	$52.24	'
Granted (in dollars per share)	$55.23	$56
Dividend equivalents (in dollars per share)	$54.45	'
Vested and released (in dollars per share)	$49.73	'
Forfeited (in dollars per share)	$54.42	'
Outstanding at the end of the period (in dollars per share)	$54.45	'
Additional disclosures	'	'
Total intrinsic value of restricted share units vested and released	$11.10	$11.40
Tax benefit realized from the vesting and release of restricted share units	4.4	4.6
Compensation cost not yet recognized	$18.70	'
Weighted-average period over which compensation cost is to be recognized	'2 years 6 months	'

STOCKBASED_COMPENSATION_NONEMP

STOCK-BASED COMPENSATION - NONEMPLOYEE DIRECTOR DEFERRED STOCK UNITS (Details) (Nonemployee director deferred stock units)	3 Months Ended
	Mar. 31, 2014
Nonemployee director deferred stock units	'
Information related to share based awards	'
Vesting period	'1 year

COMMON_EQUITY_CHANGES_TO_ISSUE

COMMON EQUITY - CHANGES TO ISSUED COMMON STOCK (Details)	3 Months Ended
	Mar. 31, 2014
Roll forward of issued common stock	'
Common Stock, Shares Issued, Balance at Beginning of the Period	79,919,176
Shares issued - Employee Stock Ownership Plan	31,764
Shares issued - Stock Investment Plan	12,151
Common Stock, Shares Issued, Balance at End of the Period	79,963,091

COMMON_EQUITY_RECONCILIATION_O

COMMON EQUITY - RECONCILIATION OF SHARES ISSUED AND OUTSTANDING (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Reconciliation of Shares Issued and Outstanding	'	'
Common stock issued (in shares)	79,963,091	79,919,176
Deferred compensation rabbi trust (in shares)	428,720	473,796
Total common shares outstanding	79,534,371	79,445,380
Average cost of shares in the rabbi trust (in dollars per share)	$48.60	$48.50

COMMON_EQUITY_EARNINGS_PER_SHA

COMMON EQUITY - EARNINGS PER SHARE (Details) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Numerator:	'	'
Net income from continuing operations	$153.20	$182.20
Discontinued operations, net of tax	-0.1	6.1
Preferred stock dividends of subsidiary	-0.8	-0.8
Noncontrolling interest in subsidiaries	0.1	0
Net income attributed to common shareholders	$152.40	$187.50
Denominator:	'	'
Average shares of common stock - basic	80.2	78.7
Effect of dilutive securities	'	'
Stock-based compensation (in shares)	0.3	0.4
Deferred compensation (in shares)	0	0.2
Average shares of common stock - diluted	80.5	79.3
Earnings per common share	'	'
Basic (in dollars per share)	$1.90	$2.38
Diluted (in dollars per share)	$1.89	$2.37
Stock-based compensation	'	'
Disclosure of antidilutive shares	'	'
Weighted-average outstanding securities that had an anti-dilutive effect	0.7	0.2
Deferred compensation	'	'
Disclosure of antidilutive shares	'	'
Weighted-average outstanding securities that had an anti-dilutive effect	0.3	0

COMMON_EQUITY_DIVIDEND_RESTRIC

COMMON EQUITY - DIVIDEND RESTRICTIONS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014
Dividend Payment Restrictions	'
Total restricted net assets	1,846.50
Equity in undistributed earnings of 50% or less owned investees accounted for by the equity method	146.8
Maximum	'
Dividend Payment Restrictions	'
Debt to capitalization ratio required to be maintained (as a percent)	65.00%
Equity method investment, ownership interest (as a percent)	50.00%
Cumulative period of interest payment deferral on Junior Subordinated Notes	'10 years
Minimum	'
Dividend Payment Restrictions	'
Number of periods for which interest payments can be deferred on Junior Subordinated Notes	1
PGL | Maximum	'
Dividend Payment Restrictions	'
Debt to capitalization ratio required to be maintained (as a percent)	65.00%
WPS | Maximum	'
Dividend Payment Restrictions	'
Debt to capitalization ratio required to be maintained (as a percent)	65.00%
WPS | Maximum | Public Service Commission of Wisconsin (PSCW)	'
Dividend Payment Restrictions	'
Percentage of previous period's dividend as restriction on current period dividends	103.00%
WPS | Minimum	'
Dividend Payment Restrictions	'
Percentage of common stockholders' equity to total capitalization required to be maintained	25.00%
WPS | Minimum | Public Service Commission of Wisconsin (PSCW)	'
Dividend Payment Restrictions	'
Common equity ratio required to be maintained (as a percent)	51.00%

COMMON_EQUITY_CAPITAL_TRANSACT

COMMON EQUITY - CAPITAL TRANSACTIONS WITH SUBSIDIARIES (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014
Capital Transactions with Subsidiaries	'
Dividends to parent	$46.30
Return of capital to parent	28.5
Equity contributions from parent	37.5
WPS Investments, LLC	'
Capital Transactions with Subsidiaries	'
Ownership interest (as a percent)	86.37%
IBS	'
Capital Transactions with Subsidiaries	'
Dividends to parent	0
Return of capital to parent	0
Equity contributions from parent	15
ITF	'
Capital Transactions with Subsidiaries	'
Dividends to parent	0
Return of capital to parent	0
Equity contributions from parent	17.4
MERC	'
Capital Transactions with Subsidiaries	'
Dividends to parent	0
Return of capital to parent	18
Equity contributions from parent	0
MGU	'
Capital Transactions with Subsidiaries	'
Dividends to parent	0
Return of capital to parent	7
Equity contributions from parent	0
UPPCO	'
Capital Transactions with Subsidiaries	'
Dividends to parent	0
Return of capital to parent	3.5
Equity contributions from parent	0
UPPCO | WPS Investments, LLC	'
Capital Transactions with Subsidiaries	'
Ownership interest (as a percent)	2.39%
WPS	'
Capital Transactions with Subsidiaries	'
Dividends to parent	28
Return of capital to parent	0
Equity contributions from parent	0
WPS | WPS Investments, LLC	'
Capital Transactions with Subsidiaries	'
Ownership interest (as a percent)	11.24%
WPS Investments, LLC	'
Capital Transactions with Subsidiaries	'
Dividends to parent	18.3
Return of capital to parent	0
Equity contributions from parent	$5.10

ACCUMULATED_OTHER_COMPREHENSIV2

ACCUMULATED OTHER COMPREHENSIVE LOSS - ROLLFORWARD (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Changes in accumulated other comprehensive loss	'	'
Accumulated other comprehensive loss, balance at beginning of period	($23.20)	($40.90)
Other comprehensive income (loss) before reclassifications	-0.1	0.1
Amounts reclassified out of accumulated other comprehensive loss	-0.3	1.5
Net current period other comprehensive income (loss)	-0.4	1.6
Accumulated other comprehensive loss, balance at end of period	-23.6	-39.3
Cash flow hedges	'	'
Changes in accumulated other comprehensive loss	'	'
Accumulated other comprehensive loss, balance at beginning of period	-3.1	-5.2
Other comprehensive income (loss) before reclassifications	0	0.1
Amounts reclassified out of accumulated other comprehensive loss	-0.6	0.9
Net current period other comprehensive income (loss)	-0.6	1
Accumulated other comprehensive loss, balance at end of period	-3.7	-4.2
Defined benefit plans	'	'
Changes in accumulated other comprehensive loss	'	'
Accumulated other comprehensive loss, balance at beginning of period	-20.1	-35.7
Other comprehensive income (loss) before reclassifications	-0.1	0
Amounts reclassified out of accumulated other comprehensive loss	0.3	0.6
Net current period other comprehensive income (loss)	0.2	0.6
Accumulated other comprehensive loss, balance at end of period	($19.90)	($35.10)

ACCUMULATED_OTHER_COMPREHENSIV3

ACCUMULATED OTHER COMPREHENSIVE LOSS - RECLASSIFICATIONS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Amount reclassified out of AOCI	'	'
Operating and maintenance expense	$364.60	$295.10
Nonregulated revenues	-1,308.20	-554.4
Interest expense	39.1	29.3
Total before taxes	-243	-291.8
Tax expense	-89.8	-109.6
Net of tax	-153.2	-182.2
Amount reclassified	'	'
Amount reclassified out of AOCI	'	'
Net of tax	-0.3	1.5
Utility segments	'	'
Amount reclassified out of AOCI	'	'
Interest expense	25.1	21.8
Tax expense	-93.6	-87.7
Net of tax	-144.7	-132.5
Losses on cash flow hedges | Amount reclassified	'	'
Amount reclassified out of AOCI	'	'
Total before taxes	0.3	1.5
Tax expense	0.9	0.6
Net of tax	-0.6	0.9
Losses on cash flow hedges | Commodity derivative contracts | Utility segments | Amount reclassified	'	'
Amount reclassified out of AOCI	'	'
Operating and maintenance expense	0	0.2
Losses on cash flow hedges | Commodity derivative contracts | Nonregulated segments | Amount reclassified	'	'
Amount reclassified out of AOCI	'	'
Nonregulated revenues	0	1.1
Losses on cash flow hedges | Interest rate hedges | Amount reclassified	'	'
Amount reclassified out of AOCI	'	'
Interest expense	0.3	0.2
Defined benefit plans | Amount reclassified	'	'
Amount reclassified out of AOCI	'	'
Amortization of prior service credits	-0.1	-0.1
Amortization of net actuarial losses	0.7	1.1
Total before taxes	0.6	1
Tax expense	0.3	0.4
Net of tax	$0.30	$0.60

VARIABLE_INTEREST_ENTITIES_Det

VARIABLE INTEREST ENTITIES (Details)	3 Months Ended
	Mar. 31, 2014
	MW
UPPCO	'
Variable interest entity	'
Obligations to purchase energy under power purchase agreement (in megawatts)	0
Contracted capacity under a power purchase agreement (in megawatts)	17.5
AMP Trillium LLC | ITF	'
Variable interest entity	'
Variable interest entity ownership interest (as a percent)	30.00%
AMP Trillium LLC | Other venturer's ownership	'
Variable interest entity	'
Variable interest entity ownership interest (as a percent)	70.00%
EVO Trillium LLC | ITF	'
Variable interest entity	'
Variable interest entity ownership interest (as a percent)	15.00%
EVO Trillium LLC | Other venturer's ownership	'
Variable interest entity	'
Variable interest entity ownership interest (as a percent)	85.00%

FAIR_VALUE_ASSETS_AND_LIABILIT

FAIR VALUE - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Assets	'	'
Risk Management Assets	$330.40	$315.50
Liabilities	'	'
Risk Management Liabilities	222	226.6
Fair value measurements on a recurring basis | Level 1	'	'
Assets	'	'
Risk Management Assets	109.6	83.9
Liabilities	'	'
Risk Management Liabilities	122.7	113.6
Fair value measurements on a recurring basis | Level 2	'	'
Assets	'	'
Risk Management Assets	168.8	177.8
Liabilities	'	'
Risk Management Liabilities	72.5	81.3
Fair value measurements on a recurring basis | Level 3	'	'
Assets	'	'
Risk Management Assets	52	53.8
Liabilities	'	'
Risk Management Liabilities	26.8	31.7
Fair value measurements on a recurring basis | Total, Fair value	'	'
Assets	'	'
Risk Management Assets	330.4	315.5
Liabilities	'	'
Risk Management Liabilities	222	226.6
Fair value measurements on a recurring basis | Utility segments | Natural gas contracts | Level 1	'	'
Assets	'	'
Risk Management Assets	0.9	2.4
Liabilities	'	'
Risk Management Liabilities	0.2	0.5
Fair value measurements on a recurring basis | Utility segments | Natural gas contracts | Level 2	'	'
Assets	'	'
Risk Management Assets	12.4	7.7
Liabilities	'	'
Risk Management Liabilities	0.2	0.6
Fair value measurements on a recurring basis | Utility segments | Natural gas contracts | Level 3	'	'
Assets	'	'
Risk Management Assets	0	0
Liabilities	'	'
Risk Management Liabilities	0	0
Fair value measurements on a recurring basis | Utility segments | Natural gas contracts | Total, Fair value	'	'
Assets	'	'
Risk Management Assets	13.3	10.1
Liabilities	'	'
Risk Management Liabilities	0.4	1.1
Fair value measurements on a recurring basis | Utility segments | FTRs | Level 1	'	'
Assets	'	'
Risk Management Assets	0	0
Liabilities	'	'
Risk Management Liabilities	0	0
Fair value measurements on a recurring basis | Utility segments | FTRs | Level 2	'	'
Assets	'	'
Risk Management Assets	0	0
Liabilities	'	'
Risk Management Liabilities	0	0
Fair value measurements on a recurring basis | Utility segments | FTRs | Level 3	'	'
Assets	'	'
Risk Management Assets	0.9	2.1
Liabilities	'	'
Risk Management Liabilities	0.2	0.3
Fair value measurements on a recurring basis | Utility segments | FTRs | Total, Fair value	'	'
Assets	'	'
Risk Management Assets	0.9	2.1
Liabilities	'	'
Risk Management Liabilities	0.2	0.3
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Level 1	'	'
Assets	'	'
Risk Management Assets	0.1	0.1
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Level 2	'	'
Assets	'	'
Risk Management Assets	0	0
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Level 3	'	'
Assets	'	'
Risk Management Assets	0	0
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Total, Fair value	'	'
Assets	'	'
Risk Management Assets	0.1	0.1
Fair value measurements on a recurring basis | Utility segments | Coal contracts | Level 1	'	'
Assets	'	'
Risk Management Assets	0	0
Liabilities	'	'
Risk Management Liabilities	0	0
Fair value measurements on a recurring basis | Utility segments | Coal contracts | Level 2	'	'
Assets	'	'
Risk Management Assets	0	0
Liabilities	'	'
Risk Management Liabilities	0	0
Fair value measurements on a recurring basis | Utility segments | Coal contracts | Level 3	'	'
Assets	'	'
Risk Management Assets	1.8	0.2
Liabilities	'	'
Risk Management Liabilities	1.5	2.7
Fair value measurements on a recurring basis | Utility segments | Coal contracts | Total, Fair value	'	'
Assets	'	'
Risk Management Assets	1.8	0.2
Liabilities	'	'
Risk Management Liabilities	1.5	2.7
Fair value measurements on a recurring basis | Nonregulated segments | Level 1	'	'
Assets	'	'
Investment in Exchange-Traded Funds	16.2	15.9
Liabilities	'	'
Contingent consideration related to the acquisition of Compass	0	0
Fair value measurements on a recurring basis | Nonregulated segments | Level 2	'	'
Assets	'	'
Investment in Exchange-Traded Funds	0	0
Liabilities	'	'
Contingent consideration related to the acquisition of Compass	0	0
Fair value measurements on a recurring basis | Nonregulated segments | Level 3	'	'
Assets	'	'
Investment in Exchange-Traded Funds	0	0
Liabilities	'	'
Contingent consideration related to the acquisition of Compass	7.8	7.8
Fair value measurements on a recurring basis | Nonregulated segments | Total, Fair value	'	'
Assets	'	'
Investment in Exchange-Traded Funds	16.2	15.9
Liabilities	'	'
Contingent consideration related to the acquisition of Compass	7.8	7.8
Fair value measurements on a recurring basis | Nonregulated segments | Natural gas contracts | Level 1	'	'
Assets	'	'
Risk Management Assets	20.6	16.3
Liabilities	'	'
Risk Management Liabilities	10.2	14.3
Fair value measurements on a recurring basis | Nonregulated segments | Natural gas contracts | Level 2	'	'
Assets	'	'
Risk Management Assets	28.8	35.2
Liabilities	'	'
Risk Management Liabilities	20.4	22
Fair value measurements on a recurring basis | Nonregulated segments | Natural gas contracts | Level 3	'	'
Assets	'	'
Risk Management Assets	27.5	35.6
Liabilities	'	'
Risk Management Liabilities	22	25.2
Fair value measurements on a recurring basis | Nonregulated segments | Natural gas contracts | Total, Fair value	'	'
Assets	'	'
Risk Management Assets	76.9	87.1
Liabilities	'	'
Risk Management Liabilities	52.6	61.5
Fair value measurements on a recurring basis | Nonregulated segments | Electric contracts | Level 1	'	'
Assets	'	'
Risk Management Assets	88	65.1
Liabilities	'	'
Risk Management Liabilities	112.3	98.8
Fair value measurements on a recurring basis | Nonregulated segments | Electric contracts | Level 2	'	'
Assets	'	'
Risk Management Assets	127.6	134.9
Liabilities	'	'
Risk Management Liabilities	51.9	58.7
Fair value measurements on a recurring basis | Nonregulated segments | Electric contracts | Level 3	'	'
Assets	'	'
Risk Management Assets	21.8	15.9
Liabilities	'	'
Risk Management Liabilities	3.1	3.5
Fair value measurements on a recurring basis | Nonregulated segments | Electric contracts | Total, Fair value	'	'
Assets	'	'
Risk Management Assets	237.4	215.9
Liabilities	'	'
Risk Management Liabilities	$167.30	$161

FAIR_VALUE_TRANSFERS_BETWEEN_L

FAIR VALUE - TRANSFERS BETWEEN LEVELS (Details) (Fair value measurements on a recurring basis, Nonregulated segments, USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Natural gas contracts	'	'
Transfers between the levels of the fair value hierarchy	'	'
Transfers into Level 2 from Level 1	$0	$0
Transfers into Level 3 from Level 1	0	0
Transfers into Level 1 from Level 2	0	0
Transfers into Level 3 from Level 2	0.9	0.2
Transfers into Level 1 from Level 3	0	0
Transfers into Level 2 from Level 3	0.1	0
Electric contracts	'	'
Transfers between the levels of the fair value hierarchy	'	'
Transfers into Level 2 from Level 1	0	0
Transfers into Level 3 from Level 1	0	0
Transfers into Level 1 from Level 2	0	0
Transfers into Level 3 from Level 2	2.6	0
Transfers into Level 1 from Level 3	0	0
Transfers into Level 2 from Level 3	$4.40	$5.50

FAIR_VALUE_SIGNIFICANT_UNOBSER

FAIR VALUE - SIGNIFICANT UNOBSERVABLE INPUTS (Details) (USD $)

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

In Millions, unless otherwise specified

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Level 3

Level 3

Utility segments

Utility segments

Utility segments

Utility segments

Utility segments

Utility segments

Utility segments

Utility segments

Utility segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

FTRs

FTRs

FTRs

Coal contracts

Coal contracts

Coal contracts

Coal contracts

Natural gas contracts

Natural gas contracts

Valuation Technique: Market-based

Contingent consideration

Contingent consideration

Contingent consideration

Natural gas contracts

Natural gas contracts

Natural gas contracts

Natural gas contracts

Electric contracts

Electric contracts

Electric contracts

Electric contracts

Electric contracts

Valuation Technique: Market-based

Valuation Technique: Market-based

Valuation Technique: Market-based

Maximum

Valuation Technique: Income-based

Valuation Technique: Income-based

Valuation Technique: Market-based

Valuation Technique: Market-based

Valuation Technique: Market-based

Valuation Technique: Market-based

Valuation Technique: Market-based

Weighted Average

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Significant internally-developed unobservable inputs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Risk Management Assets

$330.40

$315.50

$52

$53.80

$0.90

$2.10

'

$1.80

$0.20

'

'

$0

$0

'

'

'

'

'

'

$27.50

$35.60

'

'

$21.80

$15.90

'

'

'

Risk Management Liabilities

222

226.6

26.8

31.7

0.2

0.3

'

1.5

2.7

'

'

0

0

'

'

'

'

'

'

22

25.2

'

'

3.1

3.5

'

'

'

Contingent consideration related to the acquisition of Compass

'

'

'

'

'

'

'

'

'

'

'

'

'

$7.80

$7.80

'

$8

'

'

'

'

'

'

'

'

'

'

'

Forward market prices

'

'

'

'

'

'

172.92

'

'

12.11

15.25

'

'

'

'

'

'

'

'

'

'

-2.59

3.85

'

'

'

-5.02

10.06

Probability of default (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11.60%

51.00%

'

'

26.00%

'

'

Option volatilities (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

19.80%

155.60%

Monthly curve shaping (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-27.00%

'

Growth rate (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-13.20%

49.30%

'

'

'

'

'

'

'

'

'

Counterparty default time period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

FAIR_VALUE_LEVEL_3_RECONCILIAT

FAIR VALUE - LEVEL 3 RECONCILIATION (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements	'	'
Balance at the beginning of the period	$14.30	($4.90)
Net realized and unrealized gains (losses) included in earnings	6.8	13.9
Net unrealized gains (losses) recorded as regulatory assets or liabilities	2.2	2.9
Purchases	0.6	0.7
Sales	-0.7	'
Settlements	-4.8	-3.2
Net transfers into Level 3	3.5	0.2
Net transfers out of Level 3	-4.5	-5.5
Balance at the end of the period	17.4	4.1
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	6.4	13.6
Nonregulated segments | Contingent consideration	'	'
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements	'	'
Balance at the beginning of the period	-7.8	'
Net realized and unrealized gains (losses) included in earnings	0	'
Net unrealized gains (losses) recorded as regulatory assets or liabilities	0	'
Purchases	0	'
Sales	0	'
Settlements	0	'
Net transfers into Level 3	0	'
Net transfers out of Level 3	0	'
Balance at the end of the period	-7.8	'
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	0	'
Nonregulated segments | Natural gas contracts	'	'
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements	'	'
Balance at the beginning of the period	10.4	3.9
Net realized and unrealized gains (losses) included in earnings	-6.2	-1.5
Net unrealized gains (losses) recorded as regulatory assets or liabilities	0	0
Purchases	0	0
Sales	0	'
Settlements	0.5	-0.9
Net transfers into Level 3	0.9	0.2
Net transfers out of Level 3	-0.1	0
Balance at the end of the period	5.5	1.7
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	-6.2	-1.5
Nonregulated segments | Electric contracts	'	'
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements	'	'
Balance at the beginning of the period	12.4	-4.3
Net realized and unrealized gains (losses) included in earnings	12.6	15.1
Net unrealized gains (losses) recorded as regulatory assets or liabilities	0	0
Purchases	0.7	0.7
Sales	-0.7	'
Settlements	-4.5	0.1
Net transfers into Level 3	2.6	0
Net transfers out of Level 3	-4.4	-5.5
Balance at the end of the period	18.7	6.1
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	12.6	15.1
Utility segments	'	'
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements	'	'
Impact on earnings of unrealized gains (losses) on level 3 instruments	0	0
Utility segments | FTRs	'	'
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements	'	'
Balance at the beginning of the period	1.8	2
Net realized and unrealized gains (losses) included in earnings	0.4	0.3
Net unrealized gains (losses) recorded as regulatory assets or liabilities	0	-0.2
Purchases	-0.1	0
Sales	0	'
Settlements	-1.4	-1.2
Net transfers into Level 3	0	0
Net transfers out of Level 3	0	0
Balance at the end of the period	0.7	0.9
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	0	0
Utility segments | Coal contracts	'	'
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements	'	'
Balance at the beginning of the period	-2.5	-6.5
Net realized and unrealized gains (losses) included in earnings	0	0
Net unrealized gains (losses) recorded as regulatory assets or liabilities	2.2	3.1
Purchases	0	0
Sales	0	'
Settlements	0.6	-1.2
Net transfers into Level 3	0	0
Net transfers out of Level 3	0	0
Balance at the end of the period	0.3	-4.6
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	$0	$0

FAIR_VALUE_FINANCIAL_INSTRUMEN

FAIR VALUE - FINANCIAL INSTRUMENTS NOT RECORDED AT FAIR VALUE (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Carrying value and estimated fair value of financial instruments	'	'
Preferred stock	$51.10	$51.10
Carrying Amount	'	'
Carrying value and estimated fair value of financial instruments	'	'
Long-term debt	3,056.20	3,056.20
Preferred stock	51.1	51.1
Fair value	'	'
Carrying value and estimated fair value of financial instruments	'	'
Long-term debt	3,076.40	3,031.60
Preferred stock	$57.30	$61.20

ADVERTISING_COSTS_Details

ADVERTISING COSTS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Marketing and Advertising Expense [Abstract]	'	'	'
Capitalized direct-response advertising costs, net of accumulated amortization	$4.50	'	$5.20
Amortization period of direct-response advertising costs	'2 years	'	'
Amortization of direct-response advertising costs	1.3	3	'
Other advertising expense	$1.70	$2.30	'

REGULATORY_ENVIRONMENT_Details

REGULATORY ENVIRONMENT (Details) (USD $)

1 Months Ended

3 Months Ended

1 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jan. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

Nov. 30, 2013

Feb. 28, 2014

Feb. 28, 2014

Feb. 28, 2014

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Sep. 30, 2013

Jul. 31, 2012

Apr. 30, 2014

Apr. 30, 2014

Apr. 30, 2014

Apr. 30, 2014

Apr. 30, 2014

Apr. 30, 2014

Public Service Commission of Wisconsin (PSCW)

Public Service Commission of Wisconsin (PSCW)

Public Service Commission of Wisconsin (PSCW)

Public Service Commission of Wisconsin (PSCW)

Public Service Commission of Wisconsin (PSCW)

Public Service Commission of Wisconsin (PSCW)

Michigan Public Service Commission (MPSC)

Michigan Public Service Commission (MPSC)

Michigan Public Service Commission (MPSC)

Michigan Public Service Commission (MPSC)

Illinois Commerce Commission (ICC)

Illinois Commerce Commission (ICC)

Illinois Commerce Commission (ICC)

Illinois Commerce Commission (ICC)

Illinois Commerce Commission (ICC)

Illinois Commerce Commission (ICC)

Illinois Commerce Commission (ICC)

Minnesota Public Utilities Commission (MPUC)

Minnesota Public Utilities Commission (MPUC)

Minnesota Public Utilities Commission (MPUC)

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

2014 Rates

2013 Rates

Retail electric rate case

Retail electric rate case

Retail natural gas rate case

Retail natural gas rate case

MGU

MGU

Retail electric rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Public Service Commission of Wisconsin (PSCW)

Public Service Commission of Wisconsin (PSCW)

Public Service Commission of Wisconsin (PSCW)

Minnesota Public Utilities Commission (MPUC)

Minnesota Public Utilities Commission (MPUC)

Minnesota Public Utilities Commission (MPUC)

WPS

WPS

2014 Rates

2013 Rates

2014 Rates

2013 Rates

2014 Rates

2014 Rates

2015 Rates

2015 Rates

2015 Rates

2013 Rates

2013 Rates

2013 Rates

2013 Rates

2014 Rates

2014 Rates

2011 Rates

2015 Rates

Retail electric rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

WPS

WPS

WPS

WPS

UPPCO

MGU

NSG

PGL and NSG

PGL

NSG

NSG

PGL

PGL

MERC

MERC

MERC

WPS

2015 Rates

2015 Rates

2014 Rates

2014 Rates

2014 Rates

WPS

WPS

MERC

MERC

MERC

Maximum

Minimum

Regulatory Environment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Requested annual increase (decrease) in rates for customers

'

'

'

'

'

'

'

'

'

'

$7.10

'

$128.90

'

'

'

'

'

$14.20

'

'

$76.80

($1.60)

'

'

'

Requested return on common equity percent reflected in rates of customers

'

'

'

'

'

'

'

'

'

'

'

10.25%

'

'

'

'

'

'

10.75%

'

10.60%

'

'

10.75%

'

'

Requested percent of capital structure composed of common equity

'

'

'

'

'

'

'

'

'

'

50.41%

'

50.31%

'

'

'

'

'

50.31%

'

50.50%

'

'

50.31%

'

'

Approved annual increase (decrease) in rates for customers

'

'

-12.8

28.5

4

-3.4

'

'

5.8

4.5

'

'

'

'

6.6

'

57.2

'

'

11

'

'

'

'

'

'

Approved return on common equity percent reflected in rates of customers

10.20%

10.30%

'

'

'

'

'

'

10.15%

10.25%

'

'

'

'

9.28%

'

9.28%

'

'

9.70%

'

'

'

'

'

'

Approved percent of capital structure composed of common equity

50.14%

51.61%

'

'

'

'

'

'

56.74%

48.62%

'

'

'

'

50.32%

'

50.43%

'

'

50.48%

'

'

'

'

'

'

Fuel refund

'

'

'

20.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferral related to pension and other employee benefits costs

'

'

'

7.3

'

2.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recovery of income tax amounts previously expensed related to the Federal Health Care Reform Act

'

5.9

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual cap for decoupling

'

'

'

14

'

8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reversal of disallowance of depreciation expense associated with the retirement of certain assets

'

'

'

'

'

'

2.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reduction to depreciation expense

'

'

'

'

'

'

'

-2.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Adjustment to annual increase (decrease) in rates for customers

'

'

'

'

'

'

'

'

'

'

'

'

'

0.1

'

2.6

'

'

'

'

'

'

'

'

'

'

Interim annual rate increase (decrease) approved for customers

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.5

'

'

'

'

'

'

'

'

Interim rate of return on common equity approved for customers

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9.70%

'

'

'

'

'

'

'

'

Interim percent of capital structure composed of common equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.31%

'

'

'

'

'

'

'

'

Recommended rate increase (decrease) in rates for customers

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6

2.9

Amended requested annual increase (decrease) in rates for customers

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$12.20

'

'

Trial basis period for decoupling mechanism

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

Annual percent cap on decoupling based on distribution revenues approved in the rate case

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

SEGMENTS_OF_BUSINESS_Details

SEGMENTS OF BUSINESS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
	segment
Segment reporting information	'	'
Number of reportable segments	5	'
Revenues	$2,924.90	$1,678.20
Depreciation and amortization expense	71.3	60.9
Earnings from equity method investments	22.9	22.3
Miscellaneous income	6	5.7
Interest expense	39.1	29.3
Provision (benefit) for income taxes	89.8	109.6
Net income (loss) from continuing operations	153.2	182.2
Discontinued operations, net of tax	-0.1	6.1
Preferred stock dividends of subsidiary	-0.8	-0.8
Noncontrolling interest in subsidiaries	0.1	0
Net income attributed to common shareholders	152.4	187.5
ATC	'	'
Segment reporting information	'	'
Equity method investment, ownership interest (as a percent)	34.00%	'
Earnings from equity method investments	22.5	21.7
Intersegment revenues	'	'
Segment reporting information	'	'
Revenues	0	0
Holding Company and Other	'	'
Segment reporting information	'	'
Discontinued operations, net of tax	'	6
Reconciling Eliminations	'	'
Segment reporting information	'	'
Revenues	0	0
Depreciation and amortization expense	-0.1	-0.1
Earnings from equity method investments	0	0
Miscellaneous income	-3.5	-3.7
Interest expense	-3.5	-3.7
Provision (benefit) for income taxes	0	0
Net income (loss) from continuing operations	0	0
Discontinued operations, net of tax	0	0
Preferred stock dividends of subsidiary	0	0
Noncontrolling interest in subsidiaries	0	'
Net income attributed to common shareholders	0	0
Reconciling Eliminations | Intersegment revenues	'	'
Segment reporting information	'	'
Revenues	-7.5	-2.6
Regulated operations	'	'
Segment reporting information	'	'
Revenues	1,616.70	1,123.80
Depreciation and amortization expense	62	53.7
Earnings from equity method investments	22.5	21.7
Miscellaneous income	3.8	1.8
Interest expense	25.1	21.8
Provision (benefit) for income taxes	93.6	87.7
Net income (loss) from continuing operations	144.7	132.5
Discontinued operations, net of tax	0	0
Preferred stock dividends of subsidiary	-0.8	-0.8
Noncontrolling interest in subsidiaries	0	'
Net income attributed to common shareholders	143.9	131.7
Regulated operations | Intersegment revenues	'	'
Segment reporting information	'	'
Revenues	4.5	1.9
Regulated operations | Natural Gas Utility	'	'
Segment reporting information	'	'
Revenues	1,267.50	792
Depreciation and amortization expense	36.4	32.2
Earnings from equity method investments	0	0
Miscellaneous income	0.3	0.2
Interest expense	13.4	12.7
Provision (benefit) for income taxes	66.7	63.3
Net income (loss) from continuing operations	99.2	89.8
Discontinued operations, net of tax	0	0
Preferred stock dividends of subsidiary	-0.1	-0.1
Noncontrolling interest in subsidiaries	0	'
Net income attributed to common shareholders	99.1	89.7
Regulated operations | Natural Gas Utility | Intersegment revenues	'	'
Segment reporting information	'	'
Revenues	4.5	1.9
Regulated operations | Electric Utility	'	'
Segment reporting information	'	'
Revenues	349.2	331.8
Depreciation and amortization expense	25.6	21.5
Earnings from equity method investments	0	0
Miscellaneous income	3.5	1.6
Interest expense	11.7	9.1
Provision (benefit) for income taxes	18.1	16.1
Net income (loss) from continuing operations	31.8	29.3
Discontinued operations, net of tax	0	0
Preferred stock dividends of subsidiary	-0.7	-0.7
Noncontrolling interest in subsidiaries	0	'
Net income attributed to common shareholders	31.1	28.6
Regulated operations | Electric Utility | Intersegment revenues	'	'
Segment reporting information	'	'
Revenues	0	0
Regulated operations | Electric Transmission Investment	'	'
Segment reporting information	'	'
Revenues	0	0
Depreciation and amortization expense	0	0
Earnings from equity method investments	22.5	21.7
Miscellaneous income	0	0
Interest expense	0	0
Provision (benefit) for income taxes	8.8	8.3
Net income (loss) from continuing operations	13.7	13.4
Discontinued operations, net of tax	0	0
Preferred stock dividends of subsidiary	0	0
Noncontrolling interest in subsidiaries	0	'
Net income attributed to common shareholders	13.7	13.4
Regulated operations | Electric Transmission Investment | Intersegment revenues	'	'
Segment reporting information	'	'
Revenues	0	0
Nonutility and nonregulated operations | Integrys Energy Services	'	'
Segment reporting information	'	'
Revenues	1,289.60	545.4
Depreciation and amortization expense	2.9	2.7
Earnings from equity method investments	0.1	0.2
Miscellaneous income	0.3	0.4
Interest expense	0.5	0.5
Provision (benefit) for income taxes	5.9	27.3
Net income (loss) from continuing operations	10.9	51.3
Discontinued operations, net of tax	-0.1	0.1
Preferred stock dividends of subsidiary	0	0
Noncontrolling interest in subsidiaries	0	'
Net income attributed to common shareholders	10.8	51.4
Nonutility and nonregulated operations | Integrys Energy Services | Intersegment revenues	'	'
Segment reporting information	'	'
Revenues	2.6	0.3
Nonutility and nonregulated operations | Holding Company and Other	'	'
Segment reporting information	'	'
Revenues	18.6	9
Depreciation and amortization expense	6.5	4.6
Earnings from equity method investments	0.3	0.4
Miscellaneous income	5.4	7.2
Interest expense	17	10.7
Provision (benefit) for income taxes	-9.7	-5.4
Net income (loss) from continuing operations	-2.4	-1.6
Discontinued operations, net of tax	0	6
Preferred stock dividends of subsidiary	0	0
Noncontrolling interest in subsidiaries	0.1	'
Net income attributed to common shareholders	-2.3	4.4
Nonutility and nonregulated operations | Holding Company and Other | Intersegment revenues	'	'
Segment reporting information	'	'
Revenues	$0.40	$0.40