Integrys Holding (TEG) 10-Q 5 May 15 2015 Q1 Quarterly report Financial data

DOCUMENT_AND_ENTITY_INFORMATIO

DOCUMENT AND ENTITY INFORMATION	3 Months Ended
	Mar. 31, 2015	4-May-15
Document and Entity Information
Entity Registrant Name	INTEGRYS ENERGY GROUP, INC.
Entity Central Index Key	916863
Document Type	10-Q
Document Period End Date	31-Mar-15
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		79,963,091
Document Fiscal Year Focus	2015
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, 2015	Mar. 31, 2014
Income Statement [Abstract]
Operating revenues	$1,163.20	$1,638
Cost of sales	577.7	975.6
Operating and maintenance expense	261	332.6
Depreciation and amortization expense	74.7	70.6
Taxes other than income taxes	25.6	26.9
Operating income	224.2	232.3
Earnings from equity method investments	17.5	22.9
Miscellaneous income	6.6	5.8
Interest expense	38.2	38.9
Other expense	-14.1	-10.2
Income before taxes	210.1	222.1
Provision for income taxes	78.9	81.9
Net income from continuing operations	131.2	140.2
Discontinued operations, net of tax	-0.9	12.9
Net income	130.3	153.1
Preferred stock dividends of subsidiary	-0.8	-0.8
Noncontrolling interest in subsidiaries	0	0.1
Net income attributed to common shareholders	$129.50	$152.40
Average shares of common stock
Basic (in shares)	80.2	80.2
Diluted (in shares)	80.8	80.5
Earnings per common share (basic)
Net income from continuing operations (in dollars per share)	$1.62	$1.74
Discontinued operations, net of tax (in dollars per share)	($0.01)	$0.16
Earnings per common share (basic) (in dollars per share)	$1.61	$1.90
Earnings per common share (diluted)
Net income from continuing operations (in dollars per share)	$1.61	$1.73
Discontinued operations, net of tax (in dollars per share)	($0.01)	$0.16
Earnings per common share (diluted) (in dollars per share)	$1.60	$1.89
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, 2015	Mar. 31, 2014
Statement of Comprehensive Income [Abstract]
Net income	$130.30	$153.10
Cash flow hedges
Reclassification of net losses (gains) to net income, net of tax of $0.1 million and $0.9 million, respectively	0.1	-0.6
Defined benefit plans
Pension and other postretirement benefit costs arising during period, net of tax of an insignificant amount for all periods presented	0	-0.1
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.5 million and $0.3 million, respectively	0.7	0.3
Defined benefit plans, net	0.7	0.2
Other comprehensive income (loss), net of tax	0.8	-0.4
Comprehensive income	131.1	152.7
Preferred stock dividends of subsidiary	-0.8	-0.8
Noncontrolling interest in subsidiaries	0	0.1
Comprehensive income attributed to common shareholders	$130.30	$152

CONDENSED_CONSOLIDATED_STATEME2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Statement of Comprehensive Income [Abstract]
Reclassification of net losses (gains) to net income, tax	$0.10	$0.90
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, tax	$0.50	$0.30

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Assets
Cash and cash equivalents	$86.40	$18
Accounts receivable and accrued unbilled revenues, net of reserves of $58.3 and $63.3, respectively	720.8	699.8
Inventories	179.9	327.2
Regulatory assets	86.2	118.9
Assets held for sale	51.5	52.2
Deferred income taxes	39.8	52.4
Prepaid taxes	51.7	136.2
Other current assets	43	57.4
Current assets	1,259.30	1,462.10
Property, plant, and equipment, net of accumulated depreciation of $3,330.2 and $3,322.0, respectively	6,928.80	6,827.70
Regulatory assets	1,507.30	1,513.60
Equity method investments	556	550.6
Goodwill	655.4	655.4
Other long-term assets	262.2	272.6
Total assets	11,169	11,282
Liabilities and Equity
Short-term debt	133.3	317.6
Current portion of long-term debt	125	125
Accounts payable	414.6	490.7
Accrued taxes	108.6	87.7
Regulatory liabilities	171.6	153.7
Liabilities held for sale	13.6	13.8
Other current liabilities	282.1	261
Current liabilities	1,248.80	1,449.50
Long-term debt	2,956.30	2,956.30
Deferred income taxes	1,599.50	1,570
Deferred investment tax credits	63.6	60.6
Regulatory liabilities	402.4	399.9
Environmental remediation liabilities	573.2	579.9
Pension and other postretirement benefit obligations	271.2	274.6
Asset retirement obligations	485	479.1
Other long-term liabilities	155.3	161.3
Long-term liabilities	6,506.50	6,481.70
Commitments and contingencies
Common stock – $1 par value; 200,000,000 shares authorized; 79,963,091 shares issued; 79,534,171 shares outstanding	80	80
Additional paid-in capital	2,629.20	2,642.20
Retained earnings	701.1	626
Accumulated other comprehensive loss	-26.8	-27.6
Shares in deferred compensation trust	-20.9	-20.9
Total common shareholders’ equity	3,362.60	3,299.70
Preferred stock of subsidiary – $100 par value; 1,000,000 shares authorized; 511,882 shares issued; 510,495 shares outstanding	51.1	51.1
Total liabilities and equity	$11,169	$11,282

CONDENSED_CONSOLIDATED_BALANCE1

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]
Accounts receivable and accrued unbilled revenues, reserves (in dollars)	$58.30	$63.30
Property, plant, and equipment, accumulated depreciation (in dollars)	$3,330.20	$3,322
Common stock, par value (in dollars per share)	$1
Common stock, shares authorized	200,000,000
Common stock, shares issued	79,963,091	79,963,091
Common stock, shares outstanding	79,534,171	79,534,171
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, 2015	Mar. 31, 2014
Operating Activities
Net income	$130.30	$153.10
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization expense	74.7	71.3
Recoveries and refunds of regulatory assets and liabilities	18.1	54.1
Net unrealized gains on energy contracts	-0.5	-19.7
Bad debt expense	9.2	19.3
Pension and other postretirement expense	7.7	7.2
Pension and other postretirement contributions	-2.9	-68.6
Deferred income taxes and investment tax credits	45.2	90.3
Equity income, net of dividends	-4	-3.9
Other	-10.9	1.1
Changes in working capital
Collateral on deposit	0.6	-37
Accounts receivable and accrued unbilled revenues	-38.9	-531.5
Inventories	146.9	121.6
Other current assets	104.9	-65.3
Accounts payable	-40.8	272.1
Temporary LIFO liquidation credit	33.5	150.9
Other current liabilities	51.1	54.7
Net cash provided by operating activities	524.2	269.7
Investing Activities
Capital expenditures	-208.8	-159.6
Capital contributions to equity method investments	-1.7	-5.1
Withdrawal of restricted cash from Rabbi trust for qualifying payments	10.9	0
Other	2.1	1.4
Net cash used for investing activities	-197.5	-163.3
Financing Activities
Short-term debt, net	-184.3	-4.1
Shares purchased for stock-based compensation	-17.5	-9.8
Payment of dividends
Preferred stock of subsidiary	-0.8	-0.8
Common stock	-54.1	-54.1
Other	-1.6	-3.3
Net cash used for financing activities	-258.3	-72.1
Net change in cash and cash equivalents	68.4	34.3
Cash and cash equivalents at beginning of period	18	22.3
Cash and cash equivalents at end of period	86.4	56.6
Supplemental Cash Flow Information
Cash paid for interest	13.9	13.4
Cash received for income taxes	($51.10)	($62.70)

BASIS_OF_PRESENTATION

BASIS OF PRESENTATION	3 Months Ended
	Mar. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
BASIS OF PRESENTATION	Basis of Presentation
	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, 2014. 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.
	Reclassifications
	The assets and liabilities associated with the potential sale of certain PDI solar assets were reclassified as held for sale on our December 31, 2014 balance sheet to be consistent with the current period presentation. In addition, the operations of IES's retail energy business were reclassified as discontinued operations on our income statement for the three months ended March 31, 2014. See Note 4, Dispositions, for more information on these sales.

PROPOSED_MERGER_WITH_WISCONSIN

PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION	3 Months Ended
	Mar. 31, 2015
Business Combinations [Abstract]
PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION	Proposed Merger with Wisconsin Energy Corporation
	In June 2014, we entered into an Agreement and Plan of Merger (Agreement) with Wisconsin Energy Corporation (Wisconsin Energy). Under this Agreement, upon the close of the transaction our shareholders will receive 1.128 shares of Wisconsin Energy common stock and $18.58 in cash for each share of our common stock then owned. In addition, under the Agreement all of our unvested stock-based compensation awards will fully vest upon the close of the transaction and will be paid out in cash to award recipients. Upon closing of the transaction, our shareholders will own approximately 28% of the combined company, and Wisconsin Energy shareholders will own approximately 72%.
	The combined entity will be named WEC Energy Group, Inc. and will serve natural gas and electric customers across Wisconsin, Illinois, Michigan, and Minnesota.
	This transaction was approved unanimously by the Boards of Directors of both companies. It was also approved by the shareholders of both companies. In October 2014, the Department of Justice closed its review of the transaction and the Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Act. In April 2015, the transaction was approved by the Federal Communications Commission, the FERC, and the MPSC. On April 30, 2015, the transaction was verbally approved by the PSCW subject to certain conditions. A final written order is expected from the PSCW in May 2015. The transaction is still subject to approvals from the ICC and the MPUC, as well as other customary closing conditions. We expect the merger transaction to close by the end of this summer.

ACQUISITIONS

ACQUISITIONS	3 Months Ended
	Mar. 31, 2015
Business Combinations [Abstract]
ACQUISITIONS	Acquisitions
	Purchase of Alliant Energy Corporation's Natural Gas Distribution Business in Southeast Minnesota
	On April 30, 2015, MERC acquired Alliant Energy Corporation's natural gas distribution business in southeast Minnesota for $13.6 million. The purchase price included a cash payment of $11.0 million and the issuance of a promissory note to Alliant Energy Corporation for $2.6 million. The purchase price was based on the estimated book value as of the closing date and is subject to post-closing adjustments. This transaction was not material to us.

DISPOSITIONS

DISPOSITIONS	3 Months Ended
	Mar. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
DISPOSITIONS	Dispositions
	Discontinued Operations
	See Note 5, Cash and Cash Equivalents, for cash flow information related to discontinued operations.
	Holding Company and Other Segment – Potential Sale of Combined Locks Energy Center (Combined Locks)
	We are currently pursuing the sale of Combined Locks, a natural gas-fired co-generation facility located in Wisconsin. Combined Locks had $0.7 million of assets that were classified as held for sale on the balance sheets at March 31, 2015, and December 31, 2014, which included inventories and property, plant, and equipment. During each of the three months ended March 31, 2015, and 2014, we recorded after-tax losses of $0.1 million in discontinued operations related to Combined Locks.
	IES Segment – Sale of IES Retail Energy Business
	In November 2014, we sold IES's retail energy business to Exelon Generation Company, LLC (Exelon) for $331.8 million, which has been updated for a working capital adjustment made in the first quarter of 2015 and reflected in the tables below. As part of the stock purchase agreement, we provided guarantees expiring during the second quarter of 2015, which supported the IES retail energy business. See Note 12, Guarantees, for more information. We are providing certain administrative and operational services to Exelon during a transition period of up to 15 months after the sale date.
	The sale of the retail energy business was the result of a previously announced shift in our strategy to focus on our regulated businesses. Therefore, its results of operations were classified as discontinued operations beginning in the fourth quarter of 2014.
	The following table shows the carrying values of the major classes of assets and liabilities included in the sale:
		As of the Closing Date in
	(Millions)	Nov-14
	Cash and cash equivalents	$	7.6
	Accounts receivable and accrued unbilled revenues, net of reserves of $1.8	293.4
	Inventories	52.2
	Current assets from risk management activities	234.8
	Other current assets	75.1
	Property, plant, and equipment, net of accumulated depreciation of $16.6	4.5
	Long-term assets from risk management activities	106.9
	Other long-term assets	25.5
	Total assets	$	800
	Accounts payable	$	186.9
	Current liabilities from risk management activities	169.7
	Accrued taxes	0.8
	Other current liabilities	6.7
	Long-term liabilities from risk management activities	79.5
	Other long-term liabilities	0.3
	Total liabilities	$	443.9
	Included in the sale were commodity contracts that did not meet the GAAP definition of derivative instruments and, therefore, were not reflected on the balance sheets. In accordance with GAAP, expected gains or losses related to nonderivative commodity contracts are not recognized until the contracts are settled.
	The following table shows the components of discontinued operations related to the sale of the IES retail energy business recorded on the income statements for the three months ended March 31:
	(Millions)	2015			2014
	Revenues	$	—		$	1,289.60
	Cost of sales	—			(1,234.8		)
	Operating and maintenance expense	(1.2		)	(32.0		)
	Depreciation and amortization expense	—			(0.7		)
	Taxes other than income taxes	(0.2		)	(1.2		)
	Miscellaneous income	0.1			0.2
	Interest expense	—			(0.2		)
	(Loss) income before taxes	(1.3		)	20.9
	Benefit (provision) for income taxes	0.5			(7.9		)
	Discontinued operations, net of tax	$	(0.8	)	$	13
	Dispositions
	Holding Company and Other Segment – Potential Sale of Certain PDI Solar Assets
	In the first quarter of 2015, management began implementing a plan to sell certain solar assets owned by PDI. The potential sale of these assets meets the criteria in the accounting guidance to qualify as held for sale but does not meet the requirements to qualify as discontinued operations. The potential sale of these assets does not represent a shift in our corporate strategy and will not have a major effect on our operations and financial results. Therefore, the results of operations of the PDI solar assets will remain in continuing operations.
	The following table shows the carrying values of the major classes of assets and liabilities included as held for sale on the balance sheets:
	(Millions)	31-Mar-15			31-Dec-14
	Property, plant, and equipment, net of accumulated depreciation of $22.1 and $21.1, respectively	$	31.1		$	32.1
	Equity method investments	18.5			18.2
	Other long-term assets	1.2			1.2
	Total assets	$	50.8		$	51.5
	Current liabilities	$	0.3		$	0.3
	Deferred investment tax credits	4.7			5
	Asset retirement obligations	1.1			1.1
	Other long-term liabilities	7.5			7.4
	Total liabilities	$	13.6		$	13.8
	Electric Utility Segment – Sale of UPPCO
	In August 2014, we sold all of the stock of UPPCO to Balfour Beatty Infrastructure Partners LP for $336.7 million. Following the sale, we are providing certain administrative and operational services to UPPCO during a transition period of 18 to 30 months. The sale of UPPCO was evaluated for accounting purposes prior to our early adoption of ASU 2014-08. UPPCO met the criteria in the accounting guidance to qualify as held for sale but did not meet the requirements to qualify as discontinued operations as WPS has significant continuing cash flows related to certain power purchase transactions with UPPCO that continued after the sale. Therefore, UPPCO's results of operations through the sale date remain in continuing operations.

CASH_AND_CASH_EQUIVALENTS

CASH AND CASH EQUIVALENTS	3 Months Ended
	Mar. 31, 2015
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.
	Continuing Operations
	Significant noncash transactions related to continuing operations were:
		Three Months Ended March 31
	(Millions)	2015		2014
	Construction costs funded through accounts payable	$	134	$	92.3
	ITF fueling station sale financed with note receivable	2.8		—
	Equity issued for employee stock ownership plan	—		1.7
	At March 31, 2015, restricted cash of $12.5 million was recorded within other long-term assets on our balance sheet. This amount was held in the rabbi trust and represents a portion of the required funding for the rabbi trust that was triggered by the announcement of the proposed merger with Wisconsin Energy Corporation. See Note 2, Proposed Merger with Wisconsin Energy Corporation, for more information about the proposed merger. See Note 13, Employee Benefit Plans, for more information on the rabbi trust funding requirements.
	Discontinued Operations
	Significant noncash transactions and other information related to discontinued operations are disclosed below. There were no significant investing activities for the periods presented.
		Three Months Ended March 31
	(Millions)	2015		2014
	Operating Activities
	Net unrealized gains on energy contracts	$	—	$	(19.6	)
	Deferred income taxes and investment tax credits	—		11.5
	Other	1.3		6.7

INVESTMENT_IN_ATC

INVESTMENT IN ATC	3 Months Ended
	Mar. 31, 2015
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, 2015. 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)	2015		2014
	Balance at the beginning of period	$	536.7	$	508.4
	Add: Earnings from equity method investment	17		22.5
	Add: Capital contributions	1.7		5.1
	Less: Dividends received	13.6		18.4
	Balance at the end of period	$	541.8	$	517.6
	ATC is currently named in a complaint filed with the FERC requesting a reduction in the base return on equity (ROE) used by MISO transmission owners to 9.15%. ATC's current authorized ROE is 12.2%. Although we are currently unable to determine how the FERC may rule in this complaint, we believe it is probable that a refund will be required upon resolution of this issue, based on rulings in a similar complaint. As a result, our equity earnings and corresponding equity method investment in ATC reflect the impact of a reduction to earnings based on this issue. Our equity earnings for the first quarter of 2015 also included a reduction of $4.8 million related to prior years due to a revision to the estimated refund.
	Financial data for all of ATC is included in the following tables:
		Three Months Ended March 31
	(Millions)	2015		2014
	Income statement data
	Revenues	$	152.4	$	163.3
	Operating expenses	80		78.6
	Other expense	24.4		21.6
	Net income	$	48	$	63.1
	(Millions)	March 31, 2015		31-Dec-14
	Balance sheet data
	Current assets	$	69.4	$	66.4
	Noncurrent assets	3,779.30		3,728.70
	Total assets	$	3,848.70	$	3,795.10
	Current liabilities	$	325.7	$	313.1
	Long-term debt	1,701.00		1,701.00
	Other noncurrent liabilities	188.9		163.8
	Shareholders’ equity	1,633.10		1,617.20
	Total liabilities and shareholders’ equity	$	3,848.70	$	3,795.10

INVENTORIES

INVENTORIES	3 Months Ended
	Mar. 31, 2015
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, 2015, we had a temporary LIFO liquidation credit of $33.5 million recorded within other current liabilities on our balance sheet. Due to seasonality requirements, PGL and NSG expect interim reductions in LIFO layers to be replenished by year end.

GOODWILL_AND_OTHER_INTANGIBLE_

GOODWILL AND OTHER INTANGIBLE ASSETS	3 Months Ended
	Mar. 31, 2015
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, 2015, and 2014.
	The identifiable intangible assets other than goodwill listed below are part of other long-term assets on the balance sheets.
			March 31, 2015							31-Dec-14
	(Millions)		Gross Carrying		Accumulated			Net Carrying		Gross Carrying		Accumulated			Net Carrying
			Amount		Amortization			Amount		Amount		Amortization			Amount
	Amortized intangible assets
	Contractual service agreements (1)		$	15.6	$	(5.1	)	$	10.5	$	15.6	$	(4.3	)	$	11.3
	Customer-owned equipment modifications (2)		4		(1.2		)	2.8		4		(1.2		)	2.8
	Intellectual property (3)		3.4		(0.9		)	2.5		3.4		(0.8		)	2.6
	Nonregulated easements (4)		3.9		(1.5		)	2.4		3.9		(1.4		)	2.5
	Compressed natural gas fueling contract assets (5)		5.6		(3.8		)	1.8		5.6		(3.6		)	2
	Customer-related (6)		1.9		(0.4		)	1.5		1.9		(0.3		)	1.6
	Other		0.5		(0.3		)	0.2		0.5		(0.3		)	0.2
	Total		$	34.9	$	(13.2	)	$	21.7	$	34.9	$	(11.9	)	$	23
	Unamortized intangible assets
	MGU trade name		$	5.2	$	—		$	5.2	$	5.2	$	—		$	5.2
	Trillium trade name (7)		3.5		—			3.5		3.5		—			3.5
	Pinnacle trade name (7)		1.5		—			1.5		1.5		—			1.5
	Other		0.4		—			0.4		—		—			—
	Total intangible assets		$	45.5	$	(13.2	)	$	32.3	$	45.1	$	(11.9	)	$	33.2
	(1)	Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The remaining weighted-average amortization period for these intangible assets at March 31, 2015, was approximately four years.
	(2)	Relates to modifications made by PDI 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, 2015, of approximately nine years.
	(3)	Represents the fair value of intellectual property at ITF related to a system for more efficiently compressing natural gas to allow for faster fueling. The remaining amortization period for these intangible assets at March 31, 2015, was approximately seven years.
	(4)	Relates to easements supporting a pipeline at PDI. The easements are amortized on a straight-line basis, with a remaining amortization period at March 31, 2015, of approximately nine years.
	(5)	Represents the fair value of ITF contracts acquired in September 2011. The remaining amortization period for these intangible assets at March 31, 2015, was approximately six years.
	(6)	Represents customer relationship assets associated with ITF's compressed natural gas fueling operations. The remaining weighted-average amortization period for customer-related intangible assets at March 31, 2015, was approximately 12 years.
	(7)	Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) are wholly-owned subsidiaries of ITF.
	The table below shows the amortization we recorded:
			Three Months Ended March 31
	(Millions)		2015		2014
	Amortization recorded in cost of sales		$	0.3	$	0.3
	Amortization recorded in depreciation and amortization expense		0.7		0.7
	Amortization recorded in regulatory assets		0.3		—
	The following table shows our estimated amortization for the next five years, including amounts recorded through March 31, 2015:
			For the Year Ending December 31
	(Millions)		2015		2016			2017		2018		2019
	Amortization to be recorded in cost of sales		$	1.1	$	0.9		$	0.9	$	0.8	$	0.6
	Amortization to be recorded in depreciation and amortization expense		3		2.9			2.4		1.9		1.9
	Amortization to be recorded in regulatory assets		1		1			0.5		—		—

SHORTTERM_DEBT_AND_LINES_OF_CR

SHORT-TERM DEBT AND LINES OF CREDIT	3 Months Ended
	Mar. 31, 2015
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, 2015				31-Dec-14
	Commercial paper		$	133.3		*	$	317.6
	Average interest rate on commercial paper outstanding		0.37		%		0.36		%
	*	Maturity dates ranged from April 1, 2015, through April 14, 2015.
	Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2015, and 2014, was $189.5 million and $247.1 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:
	(Millions)		Maturity		March 31, 2015				31-Dec-14
	Revolving credit facility (Integrys Energy Group)		6/13/17		$	285			$	285
	Revolving credit facility (Integrys Energy Group) *		5/8/19		465				465
	Revolving credit facility (WPS)		5/8/19		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				$	1,250.00			$	1,250.00
	Less:
	Letters of credit issued inside credit facilities				$	0.7			$	3.4
	Commercial paper outstanding				133.3				317.6
	Available capacity under existing agreements				$	1,116.00			$	929
	*	This credit facility was reduced by $200.0 million in April 2015 due to the transfer of the remaining credit support for IES's retail energy business to Exelon Generation Company, LLC.

INCOME_TAXES

INCOME TAXES	3 Months Ended
	Mar. 31, 2015
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
		2015		2014
	Effective tax rate	37.6	%	36.9	%
	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, 2015, and 2014.
	During the three months ended March 31, 2015, there was not a significant change in our liability for unrecognized tax benefits.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	3 Months Ended
	Mar. 31, 2015
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 natural gas utilities have obligations to distribute and sell natural gas to their customers, and our electric utility has obligations to distribute and sell electricity to its customers. The utilities expect to recover costs related to these obligations in future customer rates.
	The following table shows our minimum future commitments related to these purchase obligations as of March 31, 2015, including those of our subsidiaries.
						Payments Due By Period
	(Millions)		Year Contracts Extend Through	Total Amounts Committed		2015		2016		2017		2018		2019		Later Years
	Natural gas utility supply and transportation		2028	$	664.6	$	128.8	$	171.7	$	134.4	$	79.6	$	52.3	$	97.8
	Electric utility
	Purchased power		2029	806.1		92.1		42.7		53.3		55.9		57.1		505
	Coal supply and transportation		2019	155.8		44.3		34.8		33.5		32.1		11.1		—
	Total			$	1,626.50	$	265.2	$	249.2	$	221.2	$	167.6	$	120.5	$	602.8
	(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, which alleged 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™, at Weston 3,
	•	changed operating conditions (including refueling, repowering, and/or retirement of units),
	•	limitations on plant emissions,
	•	beneficial environmental projects totaling $6.0 million, 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. WPS announced that certain Weston and Pulliam units mentioned in the Consent Decree will be retired early, in June 2015. WPS received approval from the PSCW in its 2015 rate order to defer and amortize the undepreciated book value of the retired plant associated with Pulliam 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding by 2023.
	WPS received approval from the PSCW in its 2014 and 2015 rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. We also believe that additional prudently incurred costs expected after 2015 will be recoverable from customers based on past precedent with the PSCW.
	The majority of the beneficial environmental projects proposed by WPS have been approved by the EPA. Amounts have been accrued and recorded to regulatory assets, excluding costs associated with capital projects.
	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, 2015. 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 alleged 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 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, and
	•	WPS's portion of a civil penalty and legal fees totaling $0.4 million.
	The Consent Decree contains a requirement to refuel, repower, or retire Edgewater 4, of which WPS is a joint owner, by no later than December 31, 2018. In the first quarter of 2015, management of the joint owners recommended that the Edgewater 4 unit be retired in December 2018. However, a final decision on how to address the requirement for this unit has not yet been made by the joint owners, as early retirement is contingent on various operational and market factors, and other alternatives to retirement are still available.
	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.
	All of the beneficial environmental projects proposed by WPS have been approved by the EPA. Amounts have been accrued and recorded to regulatory assets, excluding costs associated with capital projects.
	Weston Title V Air Permit:
	In August 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 challenged various aspects of the permit. The WDNR granted all parties' requests for contested case proceedings. The Petitions for Judicial Review, by all parties, have been stayed pending the resolution of the contested cases. In February 2014, WPS also requested a modification to the construction permit for Weston 4 to remove the mercury Best Available Control Technology (BACT) emission limit requirement. This permit request was denied by the WDNR, and WPS challenged this issue as well. At WPS's request, the permit was modified to resolve several of the petition issues. Those issues have now been voluntarily dismissed from the case, while a new permit change was challenged and added to the case. The administrative law judge (ALJ) recently dismissed some of the petition issues relating to the averaging period and monitoring issues.
	In May 2014, the WDNR issued an NOV alleging that WPS failed to maintain a minimum sorbent feed rate prior to the Continuous Emissions Monitoring System certification. The WDNR also issued a Notice of Inquiry (NOI) to WPS alleging that WPS failed to comply with reporting requirements related to challenged matters in the 2013 Weston Title V permit. The ALJ denied WPS's request to issue a stay or confirm that a statutory stay applies to the requirements identified in the NOV and NOI. The contested case is proceeding and certain legal arguments are currently being addressed in the context of summary judgment motions. No hearing date has been set.
	We do not expect these matters to have a material impact on our financial statements.
	Mercury and Interstate Air Quality Rules
	Mercury and Other Hazardous Air Pollutants:
	In December 2011, the EPA issued the final Utility Mercury and Air Toxics Standards (MATS), which regulates emissions of mercury and other hazardous air pollutants beginning in April 2015. The State of Wisconsin recently revised the compliance dates in 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. WPS placed in service capital projects for its wholly owned plants in 2015 to achieve the required reductions for MATS compliance in April 2015. These capital costs are expected to be recovered in future rates.
	Sulfur Dioxide and Nitrogen Oxide:
	In July 2011, the EPA issued a final rule known as the Cross State Air Pollution Rule (CSAPR), which numerous parties, including WPS, challenged in the United States Court of Appeals (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 (Supreme Court), and in April 2014, the Supreme Court upheld the CSAPR rule and remanded the case to the Court of Appeals for the D.C. Circuit. In October 2014, the Court of Appeals granted the EPA's request to lift the stay on CSAPR and changed the compliance deadlines by three years, so that Phase 1 emissions budgets apply in 2015 and 2016, and Phase 2 emissions budgets will apply to 2017 and beyond. We do not expect to incur significant costs to comply with either phase of CSAPR and expect to recover any future compliance costs in future rates.
	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). Although particulate emissions also contribute to visibility impairment, the WDNR's modeling for Pulliam Unit 8, the only unit covered by BART, has shown the impairment to be so insignificant that additional capital expenditures or controls may not be warranted.
	Clean Water Act Rule
	In August 2014, the EPA issued a final Clean Water Act rule, which established requirements under Section 316(b) to regulate water intake structures at industrial facilities that use large volumes of surface water as cooling water. The new rule became effective in October 2014 and has been challenged by a number of parties. The cases have been consolidated and will be heard in the United States Court of Appeals for the Second Circuit. To the extent that the rule is upheld, WPS will comply with the rule on the timeline required under the regulation. WPS will evaluate the impact of compliance by conducting the studies required by the rule at its facilities. WPS anticipates that the timing for compliance will be incorporated into future wastewater discharge permit renewals. We do not expect to incur significant costs to comply with the Clean Water Act rule at WPS's Weston plant as this plant already has two units equipped with cooling towers that assist with meeting these new requirements. We expect to recover any future compliance costs in future rates.
	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 sheet includes liabilities of $573.0 million that we have estimated and accrued for as of March 31, 2015, 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, 2015, cash expenditures for environmental remediation not yet recovered in rates were $43.1 million. Our balance sheet also includes a regulatory asset of $616.1 million at March 31, 2015, 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, 2015
Guarantees [Abstract]
GUARANTEES	Guarantees
	The following table shows our outstanding guarantees:
			Total Amounts Committed at		Expiration
	(Millions)		March 31, 2015		Less Than 1 Year		1 to 3 Years		Over 3 Years
	Guarantees supporting commodity transactions of subsidiaries (1)		$	162.5	$	91.2	$	—	$	71.3
	Standby letters of credit (2)		1.2		1.1		0.1		—
	Surety bonds (3)		25.1		25.1		—		—
	Guarantees temporarily retained related to the sale of IES's retail energy business (4)		55.7		38.6		0.8		16.3
	Other guarantees (5)		62.4		—		—		62.4
	Total guarantees		$	306.9	$	156	$	0.9	$	150
	(1)	Consists of (a) $5.0 million to support each of the business operations of IBS and PDI and (b) $0.4 million, $108.9 million, and $43.2 million related to natural gas supply at ITF, MERC, and MGU, 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 standby letters of credit issued to support ITF, MERC, MGU, NSG, PDI, PGL, and WPS. This amount is 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)	These guarantees were retained temporarily due to the sale of IES's retail energy business to Exelon Generation Company, LLC (Exelon). During the second quarter of 2015, these guarantees will expire. Exelon was contractually bound to reimburse us for any payments made under the outstanding guarantees. At March 31, 2015, these guarantees consisted of (a) $52.1 million of guarantees supporting commodity transactions; (b) $1.2 million of standby letters of credit; (c) $2.1 million of surety bonds; and (d) $0.3 million related to the sale of WPS Beaver Falls Generation, LLC. The liability related to these guarantees was insignificant. Our exposure under these guarantees related to open transactions at March 31, 2015, was $31.5 million.
	(5)	Consists of (a) $34.2 million to support PDI's future payment obligations related to its distributed solar generation projects; (b) $10.0 million related to the sale agreement for IES's Texas retail marketing business. 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) $11.2 million related to the performance of an operating and maintenance agreement by ITF; and (d) $7.0 million related to other indemnifications primarily for workers compensation coverage. The amounts discussed in items (a), (c), and (d) above are not reflected on our balance sheets.

EMPLOYEE_BENEFIT_PLANS

EMPLOYEE BENEFIT PLANS	3 Months Ended
	Mar. 31, 2015
Compensation and Retirement Disclosure [Abstract]
EMPLOYEE BENEFIT PLANS	Employee Benefit Plans
	Defined 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)	2015			2014			2015			2014
	Service cost	$	7.6		$	6.6		$	5.8		$	5.9
	Interest cost	17			19.7			5.3			7.1
	Expected return on plan assets	(26.9		)	(28.9		)	(7.9		)	(8.8		)
	Loss on plan settlement	0.5			—			—			—
	Amortization of prior service cost (credit)	0.1			0.2			(2.6		)	(1.3		)
	Amortization of net actuarial loss	10.5			8.4			1.1			0.7
	Net periodic benefit cost	$	8.8		$	6		$	1.7		$	3.6
	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.
	In March 2014, we remeasured the obligations of certain other postretirement benefit plans as a result of a plan design change to move participants age 65 and older to a Medicare Advantage plan starting January 1, 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, 2015, we contributed $2.8 million to our pension plans and $0.1 million to our other postretirement benefit plans. We expect to contribute an additional $6.3 million to our pension plans and $8.9 million to our other postretirement benefit plans during the remainder of 2015, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. In 2015, contributions of $7.0 million will be funded through a transfer of assets from the rabbi trust for certain nonqualified pension plans, of which $2.2 million was paid to participants through March 31, 2015. See the discussion below in regard to the triggering of the full funding of the rabbi trust.
	Rabbi Trust Funding Requirement
	The Agreement and Plan of Merger entered into with Wisconsin Energy Corporation in June 2014 triggered the potential change in control provisions in the rabbi trust agreement. These provisions required the full funding of the present value of each participant's total benefit under the deferred compensation program and certain nonqualified pension plans. As a result, $132.2 million, consisting of cash and exchange-traded funds, was moved to the rabbi trust during 2014 and was included in other long-term assets on the balance sheet as of March 31, 2015, and December 31, 2014. In 2015, a portion of the amounts contributed to the rabbi trust in 2014 were used to fund participant's benefits under the deferred compensation program and certain nonqualified pension plans, as discussed above. See Note 2, Proposed Merger with Wisconsin Energy Corporation, for more information on the merger.

STOCKBASED_COMPENSATION

STOCK-BASED COMPENSATION	3 Months Ended
	Mar. 31, 2015
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:
			Three Months Ended March 31
	(Millions)		2015			2014
	Stock options		$	—		$	0.3
	Performance stock rights		0.6			0.5
	Restricted share units		3.4			2.5
	Nonemployee director deferred stock units		0.2			0.2
	Total stock-based compensation expense		$	4.2		$	3.5
	Deferred income tax benefit		$	1.7		$	1.4
	No stock-based compensation cost was capitalized during the three months ended March 31, 2015, and 2014.
	Stock Options
	The weighted-average fair value per stock option granted during the three months ended March 31, 2014, was $6.70. No stock options were granted during 2015.
	A summary of stock option activity for the three months ended March 31, 2015, and information related to outstanding and exercisable stock options at March 31, 2015, 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, 2014		134,017		$	54.31
	Exercised		(45,297	)	53.32
	Outstanding at March 31, 2015		88,720		$	54.81		6.6	$	1.5
	Exercisable at March 31, 2015		53,057		$	54.84		5.9	$	0.9
	The aggregate intrinsic value for outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they all exercised their options on March 31, 2015. This is calculated as the difference between our closing stock price on March 31, 2015, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the three months ended March 31, 2015, and 2014 was not significant. Cash received from option exercises during the three months ended March 31, 2015, was $2.7 million, and was not significant for the three months ended March 31, 2014.
	Due to the accelerated vesting of all unvested stock options held by active employees in October 2014, all compensation expense related to outstanding stock options has been recognized.
	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, 2015:
	Risk-free interest rate		0.42% – 0.63%
	Expected dividend yield		5.25% – 5.33%
	Expected volatility		18% – 19%
	A summary of the activity for the three months ended March 31, 2015, related to performance stock rights accounted for as equity awards is presented below:
			Performance		Weighted-Average
			Stock Rights		Fair Value *
	Outstanding at December 31, 2014		68,263		$	58.54
	Distributed		(38,639	)	78.37
	Adjustment for payout		12,751		78.37
	Outstanding at March 31, 2015		42,375		$	46.42
	*	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, was $44.28 per performance stock right. No performance stock rights were granted during 2015.
	A summary of the activity for the three months ended March 31, 2015, related to performance stock rights accounted for as liability awards is presented below:
			Performance
			Stock Rights
	Outstanding at December 31, 2014		170,308
	Distributed		(1,746	)
	Adjustment for payout		831
	Outstanding at March 31, 2015		169,393
	The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of March 31, 2015, was $106.95 per performance stock right.
	The total intrinsic value of shares distributed during the three months ended March 31, 2015, was $3.1 million. The actual tax benefit realized for the tax deductions from the distribution of shares during the three months ended March 31, 2015, was not significant. 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.
	As of March 31, 2015, $3.3 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 1.4 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, 2015, is presented below:
			Restricted Share		Weighted-Average Grant Date Fair Value
			Unit Awards
	Outstanding at December 31, 2014		427,305		$	54.45
	Granted		224,784		77.17
	Dividend equivalents		4,437		65.31
	Vested and released		(166,545	)	53.49
	Forfeited		(530	)	52.35
	Outstanding at March 31, 2015		489,451		$	65.31
	The weighted-average grant date fair value of restricted share units awarded during the three months ended March 31, 2015, and 2014, was $77.17 and $55.23 per unit, respectively.
	The total intrinsic value of restricted share unit awards vested and released during the three months ended March 31, 2015, and 2014, was $12.8 million and $11.1 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, 2015, and 2014, was $5.1 million and $4.4 million, respectively.
	As of March 31, 2015, $20.4 million of compensation cost related to unvested and outstanding restricted share units was expected to be recognized over a weighted-average period of 2.2 years.

COMMON_EQUITY

COMMON EQUITY	3 Months Ended
	Mar. 31, 2015
Stockholders' Equity Note [Abstract]
COMMON EQUITY	Common Equity
	We had no changes to issued common stock during the three months ended March 31, 2015. Under the merger agreement with Wisconsin Energy Corporation (Wisconsin Energy), we cannot issue shares of our common stock.
	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
	The following table reconciles common shares issued and outstanding:
			March 31, 2015							December 31, 2014
			Shares			Average Cost *				Shares			Average Cost *
	Common stock issued		79,963,091							79,963,091
	Less:
	Deferred compensation rabbi trust		428,920			$	48.73			428,920			$	48.73
	Total common shares outstanding		79,534,171							79,534,171
	*	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, unvested director deferred stock units, and certain shares issuable under the deferred compensation plan. As the obligation for certain 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)		2015				2014
	Numerator:
	Net income from continuing operations		$	131.2			$	140.2
	Discontinued operations, net of tax		(0.9		)		12.9
	Preferred stock dividends of subsidiary		(0.8		)		(0.8		)
	Noncontrolling interest in subsidiaries		—				0.1
	Net income attributed to common shareholders — basic		$	129.5			$	152.4
	Effect of dilutive securities
	Deferred compensation		(0.6		)		—
	Net income attributed to common shareholders — diluted		$	128.9			$	152.4
	Denominator:
	Average shares of common stock — basic		80.2				80.2
	Effect of dilutive securities
	Stock-based compensation		0.4				0.3
	Deferred compensation		0.2				—
	Average shares of common stock — diluted		80.8				80.5
	Earnings per common share
	Basic		$	1.61			$	1.9
	Diluted		1.6				1.89
	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)		2015			2014
	Stock-based compensation		—			0.7
	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 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.
	As of March 31, 2015, total restricted net assets of consolidated subsidiaries were $1,872.6 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $158.1 million at March 31, 2015.
	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, 2015, these covenants did not restrict our retained earnings or the payment of any dividends.
	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.
	Under the merger agreement with Wisconsin Energy, we may not declare or pay any dividends or distributions on our common stock other than the regular quarterly dividend of $0.68 per share.
	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, 2015, capital transactions with subsidiaries were as follows (in millions):
	Subsidiary		Dividends To Parent				Return Of				Equity Contributions
							Capital To Parent				From Parent
	ITF (1)		$	—			$	—			$	1
	MERC		—				10.5				—
	MGU		—				13				—
	NSG (1)		7.5				—				—
	WPS		28.8				—				—
	WPS Investments, LLC (2)		13.7				—				1.7
	Total		$	50			$	23.5			$	2.7
	(1)	ITF and NSG are direct wholly owned subsidiaries of PELLC. As a result, they make distributions to PELLC, and receive 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 and WPS. At March 31, 2015, the ownership interest held by us and WPS was 89.06% and 10.94%, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2015, all equity contributions to WPS Investments, LLC were made solely by us.

ACCUMULATED_OTHER_COMPREHENSIV

ACCUMULATED OTHER COMPREHENSIVE LOSS	3 Months Ended
	Mar. 31, 2015
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:
	Three Months Ended March 31, 2015								Accumulated Other
	(Millions)		Cash Flow Hedges			Defined Benefit Plans			Comprehensive Loss
	Beginning balance at December 31, 2014		$	(3.2	)	$	(24.4	)	$	(27.6	)
	Amounts reclassified out of accumulated other comprehensive loss		0.1			0.7			0.8
	Ending balance at March 31, 2015		$	(3.1	)	$	(23.7	)	$	(26.8	)
	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 (loss) income		(0.6		)	0.2			(0.4		)
	Ending balance at March 31, 2014		$	(3.7	)	$	(19.9	)	$	(23.6	)
	The following table shows the reclassifications out of accumulated other comprehensive loss:
			Amount Reclassified
			Three Months Ended March 31						Affected Line Item in the Statements of Income
	(Millions)		2015			2014
	Losses (gains) on cash flow hedges
	Interest rate hedges		$	0.2		$	0.3		Interest expense
			0.1			0.9			Tax expense
			0.1			(0.6		)	Net of tax
	Defined benefit plans
	Amortization of prior service costs (credits)		0.3			(0.1		)	*
	Amortization of net actuarial losses		0.9			0.7			*
			1.2			0.6			Total before tax
			0.5			0.3			Tax expense
			0.7			0.3			Net of tax
	Total reclassifications		$	0.8		$	(0.3	)
	*	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, 2015
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract]
VARIABLE INTEREST ENTITIES	Variable Interest Entities
	AMP Trillium, LLC
	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. This joint venture was established to own and operate compressed natural gas (CNG) fueling stations. ITF and AMP Americas, LLC restructured AMP Trillium, LLC in April 2014. We have 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 the activities that most significantly impact its economic performance. We instead account for this variable interest entity as an equity method investment. At March 31, 2015, and December 31, 2014, the assets and liabilities on our balance sheets related to our involvement with this variable interest entity consisted of receivables, payables, and an equity investment. The following table shows the significant assets and liabilities recorded on our balance sheets related to AMP Trillium, LLC:
	(Millions)		March 31, 2015		December 31, 2014
	Assets
	Accounts receivable and accrued unbilled revenues		$	12.1	$	9.5
	Other current assets (1)		2		2
	Investment in AMP Trillium, LLC		5.4		5.5
	Other long-term assets (1)		11.3		11.8
	Liabilities
	Accounts payable		2.7		1.4
	Other current liabilities (2)		2.1		2
	(1)	Relates to notes receivable due from AMP Trillium, LLC.
	(2)	Relates to deferred revenue from the sale of CNG fueling stations to AMP Trillium, LLC.
	Our maximum exposure to loss as a result of involvement with this variable interest entity was not significant.
	EVO Trillium, LLC
	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 CNG fueling stations. We have 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 the activities that most significantly impact its economic performance. We instead account for this variable interest entity as an equity method investment. At March 31, 2015, and December 31, 2014, the assets and liabilities on our balance sheets related to our involvement with this variable interest entity consisted of receivables and payables. The following table shows the significant assets recorded on our balance sheets related to EVO Trillium, LLC:
	(Millions)		March 31, 2015		December 31, 2014
	Assets
	Accounts receivable and accrued unbilled revenues		$	7.6	$	8.8
	Other current assets *		1.1		0.5
	Other long-term assets *		4		1.7
	*	Primarily relates to notes receivable due from EVO Trillium, LLC.
	Our maximum exposure to loss as a result of involvement with this variable interest entity was not significant.

RISK_MANAGEMENT_ACTIVITIES

RISK MANAGEMENT ACTIVITIES	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
RISK MANAGEMENT ACTIVITIES	Risk Management Activities
	Utility derivatives include natural gas purchase contracts, coal purchase contracts, financial derivative contracts, and financial transmission rights (FTRs). None of these derivatives are designated as hedges for accounting purposes. The electric utility segment uses FTRs to manage electric transmission congestion costs. The natural gas and electric 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 following tables show our assets and liabilities from risk management activities at the utilities and IBS:
					March 31, 2015
	(Millions)		Balance Sheet Presentation *		Assets from				Liabilities from
					Risk Management Activities				Risk Management Activities
	Natural gas contracts		Other current		$	0.5			$	28
	Natural gas contracts		Other long-term		0.6				5.7
	FTRs		Other current		0.7				0.1
	Petroleum product contracts		Other current		—				2.1
	Coal contracts		Other current		—				4.3
	Coal contracts		Other long-term		—				3.1
			Other current		1.2				34.5
			Other long-term		0.6				8.8
	Total				$	1.8			$	43.3
	*	We classify assets and liabilities from risk management activities as current or long-term based on the maturities of the underlying contracts.
					31-Dec-14
	(Millions)		Balance Sheet Presentation *		Assets from				Liabilities from
					Risk Management Activities				Risk Management Activities
	Natural gas contracts		Other current		$	1.8			$	37.3
	Natural gas contracts		Other long-term		0.5				5.3
	FTRs		Other current		2.2				0.3
	Petroleum product contracts		Other current		—				2.7
	Petroleum product contracts		Other long-term		—				0.1
	Coal contracts		Other current		—				2.4
	Coal contracts		Other long-term		—				1
			Other current		4				42.7
			Other long-term		0.5				6.4
	Total				$	4.5			$	49.1
	*	We classify assets and liabilities from risk management activities as current or long-term based on the maturities of the underlying contracts.
	The following tables show the potential effect on our financial position of netting arrangements for recognized derivative assets and liabilities:
			March 31, 2015
	(Millions)		Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements		$	1.8			$	1.2			$	0.6
	Derivative assets not subject to master netting or similar arrangements		—								—
	Total risk management assets		$	1.8							$	0.6
	Derivative liabilities subject to master netting or similar arrangements		$	35.9			$	5.5			$	30.4
	Derivative liabilities not subject to master netting or similar arrangements		7.4								7.4
	Total risk management liabilities		$	43.3							$	37.8
			31-Dec-14
	(Millions)		Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements		$	3.2			$	1.3			$	1.9
	Derivative assets not subject to master netting or similar arrangements		1.3								1.3
	Total risk management assets		$	4.5							$	3.2
	Derivative liabilities subject to master netting or similar arrangements		$	45.7			$	8.8			$	36.9
	Derivative liabilities not subject to master netting or similar arrangements		3.4								3.4
	Total risk management liabilities		$	49.1							$	40.3
	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 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, 2015				31-Dec-14
	Cash collateral provided to others: *
	Related to contracts under master netting or similar arrangements		$	8.9			$	11.6
	Other		1.1				1.1
	*	Cash collateral provided to others is reflected in other current assets.
	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 aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a liability position at March 31, 2015, and December 31, 2014, was $31.4 million and $31.3 million, respectively. At March 31, 2015, and December 31, 2014, we had not posted any cash collateral related to the credit risk-related contingent features of these 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 at March 31, 2015, and at December 31, 2014, we would have been required to post collateral of $30.1 million and $27.1 million, respectively.
	The notional volumes of outstanding derivative contracts at the utilities and IBS were as follows:
			March 31, 2015						31-Dec-14
	(Millions)		Purchases			Other Transactions			Purchases			Other Transactions
	Natural gas (therms)		669			N/A			1,860.00			N/A
	FTRs (kilowatt-hours)		N/A			2,111.10			N/A			4,287.70
	Petroleum products (barrels)		0.1			N/A			0.1			N/A
	Coal (tons)		2.6			N/A			3			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		2015				2014
Natural gas		Balance Sheet — Regulatory assets (current)		$	10.9			$	0.9
Natural gas		Balance Sheet — Regulatory assets (long-term)		(0.6		)		(0.2		)
Natural gas		Balance Sheet — Regulatory liabilities (current)		(1.5		)		3.4
Natural gas		Balance Sheet — Regulatory liabilities (long-term)		0.1				(0.4		)
Natural gas		Income Statement — Operating and maintenance expense		(0.1		)		0.2
FTRs		Balance Sheet — Regulatory assets (current)		0.2				0.1
FTRs		Balance Sheet — Regulatory liabilities (current)		(0.4		)		(0.1		)
Petroleum		Balance Sheet — Regulatory assets (current)		0.4				—
Petroleum		Income Statement — Operating and maintenance expense		0.4				—
Coal		Balance Sheet — Regulatory assets (current)		(2.6		)		0.2
Coal		Balance Sheet — Regulatory assets (long-term)		(2.0		)		0.4
Coal		Balance Sheet — Regulatory liabilities (long-term)		—				1.6

FAIR_VALUE

FAIR VALUE	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
FAIR VALUE	Fair Value
	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.
	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.
	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 not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. 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:
	•	Financial contracts used to manage transmission congestion costs in the MISO market are valued using historical prices.
	•	The valuations for certain physical coal contracts are based on significant assumptions made to extrapolate prices from the last observable period through the end of the transaction term.
	•	Certain natural gas contracts are valued using internally-developed inputs due to the absence of available market data for certain 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 supply 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, 2015
	(Millions)		Level 1			Level 2			Level 3			Total
	Assets
	Risk Management Assets
	Natural gas contracts		$	0.1		$	1		$	—		$	1.1
	Financial transmission rights (FTRs)		—			—			0.7			0.7
	Total Risk Management Assets		$	0.1		$	1		$	0.7		$	1.8
	Investment in exchange-traded funds		$	112.3		$	—		$	—		$	112.3
	Liabilities
	Risk Management Liabilities
	Natural gas contracts		$	2.3		$	31.4		$	—		$	33.7
	Petroleum product contracts		2.1			—			—			2.1
	FTRs		—			—			0.1			0.1
	Coal contracts		—			1.2			6.2			7.4
	Total Risk Management Liabilities		$	4.4		$	32.6		$	6.3		$	43.3
			31-Dec-14
	(Millions)		Level 1			Level 2			Level 3			Total
	Assets
	Risk Management Assets
	Natural gas contracts		$	—		$	2.3		$	—		$	2.3
	FTRs		—			—			2.2			2.2
	Total Risk Management Assets		$	—		$	2.3		$	2.2		$	4.5
	Investment in exchange-traded funds		$	102.4		$	—		$	—		$	102.4
	Liabilities
	Risk Management Liabilities
	Natural gas contracts		$	4.8		$	31.2		$	6.6		$	42.6
	FTRs		—			—			0.3			0.3
	Petroleum product contracts		2.8			—			—			2.8
	Coal contracts		—			1.2			2.2			3.4
	Total Risk Management Liabilities		$	7.6		$	32.4		$	9.1		$	49.1
	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 18, Risk Management Activities, for more information.
	There were no transfers between the levels of the fair value hierarchy during the three months ended March 31, 2015, and 2014.
	The amounts 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, 2015:
			Fair Value (Millions)
			Assets			Liabilities			Valuation Technique		Unobservable Input	Average or Range
	FTRs		$	0.7		$	0.1		Market-based		Forward market prices ($/megawatt-month) (1)	$159.42
	Coal contracts		—			6.2			Market-based		Forward market prices ($/ton) (2)	$9.70 – $12.39
	(1)	Represents forward market prices developed using historical cleared pricing data from MISO.
	(2)	Represents third-party forward market pricing.
	Significant changes in historical settlement prices or forward coal prices would result in a directionally similar significant change in fair value.
	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, 2015
	(Millions)		Natural Gas Contracts			FTRs			Coal			Total
									Contracts
	Balance at the beginning of the period		$	(6.6	)	$	1.9		$	(2.2	)	$	(6.9	)
	Net realized losses included in earnings		—			(1.2		)	—			(1.2		)
	Net unrealized losses recorded as regulatory assets or liabilities		—			(0.2		)	(4.3		)	(4.5		)
	Settlements		6.6			0.1			0.3			7
Balance at the end of the period		$	—		$	0.6		$	(6.2	)	$	(5.6	)
Three Months Ended March 31, 2014
(Millions)					FTRs			Coal			Total
								Contracts
Balance at the beginning of the period					$	1.2		$	(2.5	)	$	(1.3	)
Net realized gains included in earnings					0.7			—			0.7
Net unrealized gains recorded as regulatory assets or liabilities					—			2.2			2.2
Purchases					(0.1		)	—			(0.1		)
Settlements					(1.3		)	0.6			(0.7		)
Balance at the end of the period					$	0.5		$	0.3		$	0.8
Unrealized gains and losses on Level 3 derivatives 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 cost of sales 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, 2015						31-Dec-14
(Millions)		Carrying Amount			Fair Value			Carrying Amount			Fair Value
Long-term debt		$	3,081.30		$	3,328.00		$	3,081.30		$	3,271.40
Preferred stock of subsidiary		51.1			52.3			51.1			51.8
The fair values of long-term debt instruments are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. 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.

REGULATORY_ENVIRONMENT

REGULATORY ENVIRONMENT	3 Months Ended
	Mar. 31, 2015
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	Regulatory Environment
	Wisconsin
	2016 Rate Case
	In April 2015, WPS filed an application with the PSCW to increase retail electric rates $94.1 million and increase retail natural gas rates $9.4 million, with rates expected to be effective January 1, 2016. WPS's request reflects a 10.20% return on common equity and a target common equity ratio of 50.52% in WPS's regulatory capital structure. The proposed retail electric rate increase is primarily driven by the 2016 expected completion of the ReACT™ emission control technology at Weston 3, the System Modernization and Reliability Project, and technology upgrades at the Fox Energy Center. Also included are increases in expenses for electric transmission, customer service, other operating and maintenance, and general inflation. The proposed retail natural gas rate increase is driven by the expiration of a 2015 customer refund related to decoupling, increased operating and maintenance costs, and general inflation.
	2015 Rates
	In December 2014, the PSCW issued a final written order for WPS, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million, reflecting a 10.20% return on common equity. The order also included a common equity ratio of 50.28% in WPS's regulatory capital structure. The PSCW approved a change in rate design for WPS, which includes higher fixed charges to better match the related fixed costs of providing service.
	The primary driver of the increase in retail electric rates was higher costs of fuel for electric generation of approximately $42 million. In addition, 2015 rates include approximately $9 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, WPS is refunding approximately $4 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13 million to customers in 2014 rates related to 2012 decoupling over-collections. Absent these adjustments for electric fuel costs and decoupling refunds, WPS would have realized an electric rate decrease. In addition, WPS received approval from the PSCW to defer and amortize the undepreciated book value associated with Pulliam 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding by 2023. See Note 11, Commitments and Contingencies, for more information. The PSCW is allowing WPS to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, WPS defers as a regulatory asset or liability the differences between actual transmission expenses and those included in rates. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a two percent tolerance window.
	The retail natural gas rate decrease was driven by the approximate $16 million year-over-year negative impact of decoupling refunds to and collections from customers. In 2015 rates, WPS is refunding approximately $8 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8 million from customers in 2014 rates related to 2012 decoupling under-collections. Absent the adjustment for decoupling refunds to and collections from customers, WPS would have realized a retail natural gas increase.
	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, entirely offset by a portion of estimated fuel cost over-collections from customers in 2013. Retail electric rates were further 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 of approximately $8 million 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. 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 for the Pulliam and Weston sites. See Note 11, Commitments and Contingencies, for more information. Additionally, the order required WPS to terminate its decoupling mechanism, beginning January 1, 2014.
	Michigan
	2015 WPS Rates
	In April 2015, the MPSC issued a final written order for WPS, effective April 24, 2015, approving a settlement agreement between WPS and all parties. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costs for the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generation plants. The rates reflect a 10.20% return on common equity and a target common equity ratio of 50.48% in WPS's regulatory capital structure. The increase reflects the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflects the deferral of Weston 3 ReACT™ environmental project costs. On the second anniversary of the order, WPS will discontinue the deferral of Fox Energy Center costs and will begin amortizing this deferral along with the deferral associated with the termination of a tolling agreement related to the Fox Energy Center. WPS also received approval from the MPSC to defer and amortize the undepreciated book value of the retired plant associated with Pulliam 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding by 2023. Lastly, WPS will not seek to increase retail electric base rates prior to January 1, 2018.
	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 reflected 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 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 uncollectible expense true-up mechanism after December 31, 2013.
	Illinois
	2015 Rates
	In January 2015, the ICC issued a final written order for PGL and NSG, effective January 28, 2015. The order authorized a retail natural gas rate increase of $74.8 million for PGL and $3.7 million for NSG. In February 2015, the ICC issued an amendatory order that revised the increases to $71.1 million for PGL and $3.5 million for NSG, effective February 26, 2015, to reflect the extension of bonus depreciation in 2014. The rates for PGL reflect a 9.05% return on common equity and a common equity ratio of 50.33% in PGL's regulatory capital structure. The rates for NSG reflect a 9.05% return on common equity and a common equity ratio of 50.48% in NSG's regulatory capital structure. The rate orders allowed PGL and NSG to continue the use of their decoupling mechanisms and uncollectible expense true-up mechanisms. In addition, PGL plans to recover a return on certain investments and depreciation expense through the Qualifying Infrastructure Plant rider discussed below, and accordingly, such costs are not subject to PGL's rate order. In February 2015, the Attorney General and certain intervenors filed requests for rehearing on certain issues, which the ICC denied in March 2015.
	Qualifying Infrastructure Plant 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 prudently incurred costs to upgrade Illinois natural gas infrastructure that are 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, which was approved in January 2014. The rider became effective on January 1, 2014.
	2013 Rates Amended in 2014
	In June 2013, the ICC issued a final written order for PGL and NSG, effective June 27, 2013, which authorized retail natural gas rates for both PGL and NSG. 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 Illinois Appellate Court. In January 2015, the Citizens Utility Board filed to withdraw its appeal, and the Illinois Attorney General requested an extension of the briefing schedule.
	Minnesota
	2014 Rates
	In October 2014, the MPUC issued a final written order, effective April 1, 2015. The order authorized a retail natural gas rate increase of $7.6 million. The rates reflect a 9.35% return on common equity and a common equity ratio of 50.31% in MERC's regulatory capital structure. The order approved a deferral of customer billing system costs, for which recovery will be requested in a future rate case. A decoupling mechanism with a 10% cap remains in effect for MERC's residential and small commercial and industrial customers. The final approved rate increase was lower than the interim rates collected from customers during 2014. Therefore, $4.7 million is expected to be refunded to customers beginning in June 2015, and is recorded as a regulatory liability.

SEGMENTS_OF_BUSINESS

SEGMENTS OF BUSINESS	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
SEGMENTS OF BUSINESS	Segments of Business
	At March 31, 2015, we had four segments related to our continuing operations and one segment related to the discontinued operations of IES's retail energy business. Our reportable segments are described below.
	•	The natural gas utility segment includes the natural gas utility operations of MERC, MGU, NSG, PGL, and WPS.
	•	The electric utility segment includes the electric utility operations of WPS, as well as the operations of UPPCO prior to its sale to Balfour Beatty Infrastructure Partners LP in August 2014. See Note 4, Dispositions, for more information on the sale of UPPCO.
	•	The electric transmission investment segment includes our approximate 34% ownership interest in ATC. ATC is a federally regulated electric transmission company.
	•	The IES segment includes the nonregulated energy operations of IES's retail energy business. Since we sold IES's retail energy business in November 2014, this segment only includes discontinued operations. See Note 4, Dispositions, for more information on the sale of IES's retail energy business. The remaining energy asset business, PDI, was reclassified to the holding company and other segment.
	•	The holding company and other segment includes the operations of the Integrys Energy Group holding company, ITF, PDI, 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, 2015
	External revenues		$	839.5		$	295.8		$	—	$	1,135.30		$	—		$	27.9		$	—		$	1,163.20
	Intersegment revenues		2.6			—			—		2.6			—			0.2			(2.8		)	—
	Depreciation and amortization expense		40.6			25			—		65.6			—			9.2			(0.1		)	74.7
	Earnings from equity method investments		—			—			17		17			—			0.5			—			17.5
	Miscellaneous income		0.7			2.8			—		3.5			—			5.1			(2.0		)	6.6
	Interest expense		14.3			10.9			—		25.2			—			15			(2.0		)	38.2
	Provision (benefit) for income taxes		65.9			16.4			6.7		89			—			(10.1		)	—			78.9
	Net income (loss) from continuing operations		97.8			28.6			10.3		136.7			—			(5.5		)	—			131.2
	Discontinued operations		—			—			—		—			(0.8		)	(0.1		)	—			(0.9		)
	Preferred stock dividends of subsidiary		(0.1		)	(0.7		)	—		(0.8		)	—			—			—			(0.8		)
	Net income (loss) attributed to common shareholders		97.7			27.9			10.3		135.9			(0.8		)	(5.6		)	—			129.5
			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-14
	External revenues		$	1,267.60		$	349.2		$	—	$	1,616.80		$	—		$	21.2		$	—		$	1,638.00
	Intersegment revenues		4.4			—			—		4.4			—			0.4			(4.8		)	—
	Depreciation and amortization expense		36.4			25.6			—		62			—			8.7			(0.1		)	70.6
	Earnings from equity method investments		—			—			22.5		22.5			—			0.4			—			22.9
	Miscellaneous income		0.3			3.5			—		3.8			—			5.3			(3.3		)	5.8
	Interest expense		13.4			11.7			—		25.1			—			17.1			(3.3		)	38.9
	Provision (benefit) for income taxes		66.7			18.1			8.8		93.6			—			(11.7		)	—			81.9
	Net income (loss) from continuing operations		99.2			31.8			13.7		144.7			—			(4.5		)	—			140.2
	Discontinued operations		—			—			—		—			13			(0.1		)	—			12.9
	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			13			(4.5		)	—			152.4

NEW_ACCOUNTING_PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS	3 Months Ended
	Mar. 31, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
NEW ACCOUNTING PRONOUNCEMENTS	New Accounting Pronouncements
	Recently Issued Accounting Guidance Not Yet Effective
	In April 2015 the FASB issued ASU 2015-05, "Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement." The ASU provides guidance for determining whether a cloud computing arrangement includes a software license, which should be accounted for consistent with the acquisition of other software licenses. Cloud computing arrangements that do not include a software license should be accounted for as service contracts. This guidance may be applied either prospectively to new cloud computing arrangements, or retrospectively by restating each prior period presented in the financial statements. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact that the adoption of this standard will have on our financial statements.
	In April 2015 the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs." The guidance requires debt issuance costs to be presented on the balance sheet as a reduction to the carrying value of the corresponding debt, rather than as an asset as it is currently presented. The standard requires retrospective application by restating each prior period presented in the financial statements. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact this guidance will have on our financial statements.
	In February 2015 the FASB issued ASU 2015-02, "Amendments to the Consolidation Analysis." The guidance focuses on the consolidation evaluation for companies that are required to evaluate whether they should consolidate certain legal entities. It places more emphasis on risk of loss when determining a controlling financial interest and amends the guidance for assessing how relationships of related parties affect the consolidation analysis of variable interest entities. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact this guidance will have on our financial statements.
	In January 2015 the FASB issued ASU 2015-01, "Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items." This guidance eliminates the disclosure of extraordinary items, net of tax, in the income statement after income from continuing operations. The guidance is effective for us for the reporting period ending March 31, 2016. We do not currently have any extraordinary items presented on the income statements. However, this guidance will eliminate the need for us to further assess whether unusual and infrequently occurring transactions qualify as extraordinary items in the future.
	In May 2014 the FASB issued ASU 2014-09, "Revenue from Contracts with Customers." This ASU supersedes the requirements in the Revenue Recognition Topic of the FASB ASC and most industry-specific guidance throughout the ASC. The guidance is based on the principle that revenue is recognized when promised goods or services are transferred to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The standard requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and cash flows from customer contracts. The guidance is currently effective for us for the reporting period ending March 31, 2017; however, in April 2015 the FASB issued an exposure draft proposing to delay the effective date for one year. The standard requires either retrospective application by restating each prior period presented in the financial statements, or modified retrospective application by recording the cumulative effect of prior reporting periods to beginning retained earnings in the year that the standard becomes effective. We are currently evaluating the impact that the adoption of this standard will have on our financial statements.

BASIS_OF_PRESENTATION_Policies

BASIS OF PRESENTATION (Policies)	3 Months Ended
	Mar. 31, 2015
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, 2014. 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.
Reclassifications	Reclassifications
	The assets and liabilities associated with the potential sale of certain PDI solar assets were reclassified as held for sale on our December 31, 2014 balance sheet to be consistent with the current period presentation. In addition, the operations of IES's retail energy business were reclassified as discontinued operations on our income statement for the three months ended March 31, 2014. See Note 4, Dispositions, for more information on these sales.
Cash and cash equivalents	Short-term investments with an original maturity of three months or less are reported as cash equivalents.
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.
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, unvested director deferred stock units, and certain shares issuable under the deferred compensation plan. As the obligation for certain 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.
	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.
	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 not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. 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:
	•	Financial contracts used to manage transmission congestion costs in the MISO market are valued using historical prices.
	•	The valuations for certain physical coal contracts are based on significant assumptions made to extrapolate prices from the last observable period through the end of the transaction term.
	•	Certain natural gas contracts are valued using internally-developed inputs due to the absence of available market data for certain 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 supply 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.
New accounting pronouncements	In April 2015 the FASB issued ASU 2015-05, "Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement." The ASU provides guidance for determining whether a cloud computing arrangement includes a software license, which should be accounted for consistent with the acquisition of other software licenses. Cloud computing arrangements that do not include a software license should be accounted for as service contracts. This guidance may be applied either prospectively to new cloud computing arrangements, or retrospectively by restating each prior period presented in the financial statements. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact that the adoption of this standard will have on our financial statements.
	In April 2015 the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs." The guidance requires debt issuance costs to be presented on the balance sheet as a reduction to the carrying value of the corresponding debt, rather than as an asset as it is currently presented. The standard requires retrospective application by restating each prior period presented in the financial statements. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact this guidance will have on our financial statements.
	In February 2015 the FASB issued ASU 2015-02, "Amendments to the Consolidation Analysis." The guidance focuses on the consolidation evaluation for companies that are required to evaluate whether they should consolidate certain legal entities. It places more emphasis on risk of loss when determining a controlling financial interest and amends the guidance for assessing how relationships of related parties affect the consolidation analysis of variable interest entities. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact this guidance will have on our financial statements.
	In January 2015 the FASB issued ASU 2015-01, "Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items." This guidance eliminates the disclosure of extraordinary items, net of tax, in the income statement after income from continuing operations. The guidance is effective for us for the reporting period ending March 31, 2016. We do not currently have any extraordinary items presented on the income statements. However, this guidance will eliminate the need for us to further assess whether unusual and infrequently occurring transactions qualify as extraordinary items in the future.
	In May 2014 the FASB issued ASU 2014-09, "Revenue from Contracts with Customers." This ASU supersedes the requirements in the Revenue Recognition Topic of the FASB ASC and most industry-specific guidance throughout the ASC. The guidance is based on the principle that revenue is recognized when promised goods or services are transferred to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The standard requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and cash flows from customer contracts. The guidance is currently effective for us for the reporting period ending March 31, 2017; however, in April 2015 the FASB issued an exposure draft proposing to delay the effective date for one year. The standard requires either retrospective application by restating each prior period presented in the financial statements, or modified retrospective application by recording the cumulative effect of prior reporting periods to beginning retained earnings in the year that the standard becomes effective. We are currently evaluating the impact that the adoption of this standard will have on our financial statements.
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.

DISPOSITIONS_Tables

DISPOSITIONS (Tables)	3 Months Ended
	Mar. 31, 2015
IES | IES's retail energy business
Dispositions
Carrying values of major classes of assets and liabilities classified as held for sale on balance sheets as well as discontinued operations included on income statements	The following table shows the carrying values of the major classes of assets and liabilities included in the sale:
		As of the Closing Date in
	(Millions)	Nov-14
	Cash and cash equivalents	$	7.6
	Accounts receivable and accrued unbilled revenues, net of reserves of $1.8	293.4
	Inventories	52.2
	Current assets from risk management activities	234.8
	Other current assets	75.1
	Property, plant, and equipment, net of accumulated depreciation of $16.6	4.5
	Long-term assets from risk management activities	106.9
	Other long-term assets	25.5
	Total assets	$	800
	Accounts payable	$	186.9
	Current liabilities from risk management activities	169.7
	Accrued taxes	0.8
	Other current liabilities	6.7
	Long-term liabilities from risk management activities	79.5
	Other long-term liabilities	0.3
	Total liabilities	$	443.9
	Included in the sale were commodity contracts that did not meet the GAAP definition of derivative instruments and, therefore, were not reflected on the balance sheets. In accordance with GAAP, expected gains or losses related to nonderivative commodity contracts are not recognized until the contracts are settled.
	The following table shows the components of discontinued operations related to the sale of the IES retail energy business recorded on the income statements for the three months ended March 31:
	(Millions)	2015			2014
	Revenues	$	—		$	1,289.60
	Cost of sales	—			(1,234.8		)
	Operating and maintenance expense	(1.2		)	(32.0		)
	Depreciation and amortization expense	—			(0.7		)
	Taxes other than income taxes	(0.2		)	(1.2		)
	Miscellaneous income	0.1			0.2
	Interest expense	—			(0.2		)
	(Loss) income before taxes	(1.3		)	20.9
	Benefit (provision) for income taxes	0.5			(7.9		)
	Discontinued operations, net of tax	$	(0.8	)	$	13
Holding Company and Other | PDI Solar Assets
Dispositions
Carrying values of major classes of assets and liabilities classified as held for sale on balance sheets as well as discontinued operations included on income statements	The following table shows the carrying values of the major classes of assets and liabilities included as held for sale on the balance sheets:
	(Millions)	31-Mar-15			31-Dec-14
	Property, plant, and equipment, net of accumulated depreciation of $22.1 and $21.1, respectively	$	31.1		$	32.1
	Equity method investments	18.5			18.2
	Other long-term assets	1.2			1.2
	Total assets	$	50.8		$	51.5
	Current liabilities	$	0.3		$	0.3
	Deferred investment tax credits	4.7			5
	Asset retirement obligations	1.1			1.1
	Other long-term liabilities	7.5			7.4
	Total liabilities	$	13.6		$	13.8

CASH_AND_CASH_EQUIVALENTS_Tabl

CASH AND CASH EQUIVALENTS (Tables)	3 Months Ended
	Mar. 31, 2015
Continuing operations
Significant noncash transactions
Table of significant noncash transactions	Significant noncash transactions related to continuing operations were:
		Three Months Ended March 31
	(Millions)	2015		2014
	Construction costs funded through accounts payable	$	134	$	92.3
	ITF fueling station sale financed with note receivable	2.8		—
	Equity issued for employee stock ownership plan	—		1.7
Discontinued operations
Significant noncash transactions
Table of significant noncash transactions	Significant noncash transactions and other information related to discontinued operations are disclosed below. There were no significant investing activities for the periods presented.
		Three Months Ended March 31
	(Millions)	2015		2014
	Operating Activities
	Net unrealized gains on energy contracts	$	—	$	(19.6	)
	Deferred income taxes and investment tax credits	—		11.5
	Other	1.3		6.7

INVESTMENT_IN_ATC_Tables

INVESTMENT IN ATC (Tables) (ATC)	3 Months Ended
	Mar. 31, 2015
ATC
Investment in ATC
Schedule of changes to our investment in ATC	The following table shows changes to our investment in ATC:
		Three Months Ended March 31
	(Millions)	2015		2014
	Balance at the beginning of period	$	536.7	$	508.4
	Add: Earnings from equity method investment	17		22.5
	Add: Capital contributions	1.7		5.1
	Less: Dividends received	13.6		18.4
	Balance at the end of period	$	541.8	$	517.6
Schedule of summarized income statement data for ATC	Financial data for all of ATC is included in the following tables:
		Three Months Ended March 31
	(Millions)	2015		2014
	Income statement data
	Revenues	$	152.4	$	163.3
	Operating expenses	80		78.6
	Other expense	24.4		21.6
	Net income	$	48	$	63.1
Schedule of summarized balance sheet data for ATC
	(Millions)	March 31, 2015		31-Dec-14
	Balance sheet data
	Current assets	$	69.4	$	66.4
	Noncurrent assets	3,779.30		3,728.70
	Total assets	$	3,848.70	$	3,795.10
	Current liabilities	$	325.7	$	313.1
	Long-term debt	1,701.00		1,701.00
	Other noncurrent liabilities	188.9		163.8
	Shareholders’ equity	1,633.10		1,617.20
	Total liabilities and shareholders’ equity	$	3,848.70	$	3,795.10

GOODWILL_AND_OTHER_INTANGIBLE_1

GOODWILL AND OTHER INTANGIBLE ASSETS (Tables)	3 Months Ended
	Mar. 31, 2015
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 long-term assets on the balance sheets.
			March 31, 2015							31-Dec-14
	(Millions)		Gross Carrying		Accumulated			Net Carrying		Gross Carrying		Accumulated			Net Carrying
			Amount		Amortization			Amount		Amount		Amortization			Amount
	Amortized intangible assets
	Contractual service agreements (1)		$	15.6	$	(5.1	)	$	10.5	$	15.6	$	(4.3	)	$	11.3
	Customer-owned equipment modifications (2)		4		(1.2		)	2.8		4		(1.2		)	2.8
	Intellectual property (3)		3.4		(0.9		)	2.5		3.4		(0.8		)	2.6
	Nonregulated easements (4)		3.9		(1.5		)	2.4		3.9		(1.4		)	2.5
	Compressed natural gas fueling contract assets (5)		5.6		(3.8		)	1.8		5.6		(3.6		)	2
	Customer-related (6)		1.9		(0.4		)	1.5		1.9		(0.3		)	1.6
	Other		0.5		(0.3		)	0.2		0.5		(0.3		)	0.2
	Total		$	34.9	$	(13.2	)	$	21.7	$	34.9	$	(11.9	)	$	23
	Unamortized intangible assets
	MGU trade name		$	5.2	$	—		$	5.2	$	5.2	$	—		$	5.2
	Trillium trade name (7)		3.5		—			3.5		3.5		—			3.5
	Pinnacle trade name (7)		1.5		—			1.5		1.5		—			1.5
	Other		0.4		—			0.4		—		—			—
	Total intangible assets		$	45.5	$	(13.2	)	$	32.3	$	45.1	$	(11.9	)	$	33.2
	(1)	Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The remaining weighted-average amortization period for these intangible assets at March 31, 2015, was approximately four years.
	(2)	Relates to modifications made by PDI 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, 2015, of approximately nine years.
	(3)	Represents the fair value of intellectual property at ITF related to a system for more efficiently compressing natural gas to allow for faster fueling. The remaining amortization period for these intangible assets at March 31, 2015, was approximately seven years.
	(4)	Relates to easements supporting a pipeline at PDI. The easements are amortized on a straight-line basis, with a remaining amortization period at March 31, 2015, of approximately nine years.
	(5)	Represents the fair value of ITF contracts acquired in September 2011. The remaining amortization period for these intangible assets at March 31, 2015, was approximately six years.
	(6)	Represents customer relationship assets associated with ITF's compressed natural gas fueling operations. The remaining weighted-average amortization period for customer-related intangible assets at March 31, 2015, was approximately 12 years.
	(7)	Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) are wholly-owned subsidiaries of ITF.
Schedule of intangible asset amortization	The table below shows the amortization we recorded:
			Three Months Ended March 31
	(Millions)		2015		2014
	Amortization recorded in cost of sales		$	0.3	$	0.3
	Amortization recorded in depreciation and amortization expense		0.7		0.7
	Amortization recorded in regulatory assets		0.3		—
Schedule of intangible asset amortization for the next five years	The following table shows our estimated amortization for the next five years, including amounts recorded through March 31, 2015:
			For the Year Ending December 31
	(Millions)		2015		2016			2017		2018		2019
	Amortization to be recorded in cost of sales		$	1.1	$	0.9		$	0.9	$	0.8	$	0.6
	Amortization to be recorded in depreciation and amortization expense		3		2.9			2.4		1.9		1.9
	Amortization to be recorded in regulatory assets		1		1			0.5		—		—

SHORTTERM_DEBT_AND_LINES_OF_CR1

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)	3 Months Ended
	Mar. 31, 2015
Short-term Debt [Abstract]
Schedule of short-term borrowings	Our outstanding short-term borrowings were as follows:
	(Millions, except percentages)		March 31, 2015				31-Dec-14
	Commercial paper		$	133.3		*	$	317.6
	Average interest rate on commercial paper outstanding		0.37		%		0.36		%
	*	Maturity dates ranged from April 1, 2015, through April 14, 2015.
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:
	(Millions)		Maturity		March 31, 2015				31-Dec-14
	Revolving credit facility (Integrys Energy Group)		6/13/17		$	285			$	285
	Revolving credit facility (Integrys Energy Group) *		5/8/19		465				465
	Revolving credit facility (WPS)		5/8/19		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				$	1,250.00			$	1,250.00
	Less:
	Letters of credit issued inside credit facilities				$	0.7			$	3.4
	Commercial paper outstanding				133.3				317.6
	Available capacity under existing agreements				$	1,116.00			$	929
	*	This credit facility was reduced by $200.0 million in April 2015 due to the transfer of the remaining credit support for IES's retail energy business to Exelon Generation Company, LLC.

INCOME_TAXES_Tables

INCOME TAXES (Tables)	3 Months Ended
	Mar. 31, 2015
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
		2015		2014
	Effective tax rate	37.6	%	36.9	%

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Tables)	3 Months Ended
	Mar. 31, 2015
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, 2015, including those of our subsidiaries.
					Payments Due By Period
	(Millions)	Year Contracts Extend Through	Total Amounts Committed		2015		2016		2017		2018		2019		Later Years
	Natural gas utility supply and transportation	2028	$	664.6	$	128.8	$	171.7	$	134.4	$	79.6	$	52.3	$	97.8
	Electric utility
	Purchased power	2029	806.1		92.1		42.7		53.3		55.9		57.1		505
	Coal supply and transportation	2019	155.8		44.3		34.8		33.5		32.1		11.1		—
	Total		$	1,626.50	$	265.2	$	249.2	$	221.2	$	167.6	$	120.5	$	602.8

GUARANTEES_Tables

GUARANTEES (Tables)	3 Months Ended
	Mar. 31, 2015
Guarantees [Abstract]
Schedule of outstanding guarantees	The following table shows our outstanding guarantees:
			Total Amounts Committed at		Expiration
	(Millions)		March 31, 2015		Less Than 1 Year		1 to 3 Years		Over 3 Years
	Guarantees supporting commodity transactions of subsidiaries (1)		$	162.5	$	91.2	$	—	$	71.3
	Standby letters of credit (2)		1.2		1.1		0.1		—
	Surety bonds (3)		25.1		25.1		—		—
	Guarantees temporarily retained related to the sale of IES's retail energy business (4)		55.7		38.6		0.8		16.3
	Other guarantees (5)		62.4		—		—		62.4
	Total guarantees		$	306.9	$	156	$	0.9	$	150
	(1)	Consists of (a) $5.0 million to support each of the business operations of IBS and PDI and (b) $0.4 million, $108.9 million, and $43.2 million related to natural gas supply at ITF, MERC, and MGU, 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 standby letters of credit issued to support ITF, MERC, MGU, NSG, PDI, PGL, and WPS. This amount is 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)	These guarantees were retained temporarily due to the sale of IES's retail energy business to Exelon Generation Company, LLC (Exelon). During the second quarter of 2015, these guarantees will expire. Exelon was contractually bound to reimburse us for any payments made under the outstanding guarantees. At March 31, 2015, these guarantees consisted of (a) $52.1 million of guarantees supporting commodity transactions; (b) $1.2 million of standby letters of credit; (c) $2.1 million of surety bonds; and (d) $0.3 million related to the sale of WPS Beaver Falls Generation, LLC. The liability related to these guarantees was insignificant. Our exposure under these guarantees related to open transactions at March 31, 2015, was $31.5 million.
	(5)	Consists of (a) $34.2 million to support PDI's future payment obligations related to its distributed solar generation projects; (b) $10.0 million related to the sale agreement for IES's Texas retail marketing business. 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) $11.2 million related to the performance of an operating and maintenance agreement by ITF; and (d) $7.0 million related to other indemnifications primarily for workers compensation coverage. The amounts discussed in items (a), (c), and (d) above are not reflected on our balance sheets.

EMPLOYEE_BENEFIT_PLANS_Tables

EMPLOYEE BENEFIT PLANS (Tables)	3 Months Ended
	Mar. 31, 2015
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)	2015			2014			2015			2014
	Service cost	$	7.6		$	6.6		$	5.8		$	5.9
	Interest cost	17			19.7			5.3			7.1
	Expected return on plan assets	(26.9		)	(28.9		)	(7.9		)	(8.8		)
	Loss on plan settlement	0.5			—			—			—
	Amortization of prior service cost (credit)	0.1			0.2			(2.6		)	(1.3		)
	Amortization of net actuarial loss	10.5			8.4			1.1			0.7
	Net periodic benefit cost	$	8.8		$	6		$	1.7		$	3.6

STOCKBASED_COMPENSATION_Tables

STOCK-BASED COMPENSATION (Tables)	3 Months Ended
	Mar. 31, 2015
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:
			Three Months Ended March 31
	(Millions)		2015			2014
	Stock options		$	—		$	0.3
	Performance stock rights		0.6			0.5
	Restricted share units		3.4			2.5
	Nonemployee director deferred stock units		0.2			0.2
	Total stock-based compensation expense		$	4.2		$	3.5
	Deferred income tax benefit		$	1.7		$	1.4
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, 2015, and information related to outstanding and exercisable stock options at March 31, 2015, 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, 2014		134,017		$	54.31
	Exercised		(45,297	)	53.32
	Outstanding at March 31, 2015		88,720		$	54.81		6.6	$	1.5
	Exercisable at March 31, 2015		53,057		$	54.84		5.9	$	0.9
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, 2015:
	Risk-free interest rate		0.42% – 0.63%
	Expected dividend yield		5.25% – 5.33%
	Expected volatility		18% – 19%
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, 2015, is presented below:
			Restricted Share		Weighted-Average Grant Date Fair Value
			Unit Awards
	Outstanding at December 31, 2014		427,305		$	54.45
	Granted		224,784		77.17
	Dividend equivalents		4,437		65.31
	Vested and released		(166,545	)	53.49
	Forfeited		(530	)	52.35
	Outstanding at March 31, 2015		489,451		$	65.31
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, 2015, related to performance stock rights accounted for as equity awards is presented below:
			Performance		Weighted-Average
			Stock Rights		Fair Value *
	Outstanding at December 31, 2014		68,263		$	58.54
	Distributed		(38,639	)	78.37
	Adjustment for payout		12,751		78.37
	Outstanding at March 31, 2015		42,375		$	46.42
	*	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, 2015, related to performance stock rights accounted for as liability awards is presented below:
			Performance
			Stock Rights
	Outstanding at December 31, 2014		170,308
	Distributed		(1,746	)
	Adjustment for payout		831
	Outstanding at March 31, 2015		169,393

COMMON_EQUITY_Tables

COMMON EQUITY (Tables)	3 Months Ended
	Mar. 31, 2015
Stockholders' Equity Note [Abstract]
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
Reconciliation of shares issued and outstanding	The following table reconciles common shares issued and outstanding:
			March 31, 2015							December 31, 2014
			Shares			Average Cost *				Shares			Average Cost *
	Common stock issued		79,963,091							79,963,091
	Less:
	Deferred compensation rabbi trust		428,920			$	48.73			428,920			$	48.73
	Total common shares outstanding		79,534,171							79,534,171
	*	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)		2015				2014
	Numerator:
	Net income from continuing operations		$	131.2			$	140.2
	Discontinued operations, net of tax		(0.9		)		12.9
	Preferred stock dividends of subsidiary		(0.8		)		(0.8		)
	Noncontrolling interest in subsidiaries		—				0.1
	Net income attributed to common shareholders — basic		$	129.5			$	152.4
	Effect of dilutive securities
	Deferred compensation		(0.6		)		—
	Net income attributed to common shareholders — diluted		$	128.9			$	152.4
	Denominator:
	Average shares of common stock — basic		80.2				80.2
	Effect of dilutive securities
	Stock-based compensation		0.4				0.3
	Deferred compensation		0.2				—
	Average shares of common stock — diluted		80.8				80.5
	Earnings per common share
	Basic		$	1.61			$	1.9
	Diluted		1.6				1.89
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)		2015			2014
	Stock-based compensation		—			0.7
	Deferred compensation		—			0.3
Capital transactions with subsidiaries	During the three months ended March 31, 2015, capital transactions with subsidiaries were as follows (in millions):
	Subsidiary		Dividends To Parent				Return Of				Equity Contributions
							Capital To Parent				From Parent
	ITF (1)		$	—			$	—			$	1
	MERC		—				10.5				—
	MGU		—				13				—
	NSG (1)		7.5				—				—
	WPS		28.8				—				—
	WPS Investments, LLC (2)		13.7				—				1.7
	Total		$	50			$	23.5			$	2.7
	(1)	ITF and NSG are direct wholly owned subsidiaries of PELLC. As a result, they make distributions to PELLC, and receive 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 and WPS. At March 31, 2015, the ownership interest held by us and WPS was 89.06% and 10.94%, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2015, 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, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule of changes, net of tax, to accumulated other comprehensive loss	The following tables show the changes, net of tax, to our accumulated other comprehensive loss:
	Three Months Ended March 31, 2015								Accumulated Other
	(Millions)		Cash Flow Hedges			Defined Benefit Plans			Comprehensive Loss
	Beginning balance at December 31, 2014		$	(3.2	)	$	(24.4	)	$	(27.6	)
	Amounts reclassified out of accumulated other comprehensive loss		0.1			0.7			0.8
	Ending balance at March 31, 2015		$	(3.1	)	$	(23.7	)	$	(26.8	)
	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 (loss) income		(0.6		)	0.2			(0.4		)
	Ending balance at March 31, 2014		$	(3.7	)	$	(19.9	)	$	(23.6	)
Schedule of reclassifications out of accumulated other comprehensive loss	The following table shows the reclassifications out of accumulated other comprehensive loss:
			Amount Reclassified
			Three Months Ended March 31						Affected Line Item in the Statements of Income
	(Millions)		2015			2014
	Losses (gains) on cash flow hedges
	Interest rate hedges		$	0.2		$	0.3		Interest expense
			0.1			0.9			Tax expense
			0.1			(0.6		)	Net of tax
	Defined benefit plans
	Amortization of prior service costs (credits)		0.3			(0.1		)	*
	Amortization of net actuarial losses		0.9			0.7			*
			1.2			0.6			Total before tax
			0.5			0.3			Tax expense
			0.7			0.3			Net of tax
	Total reclassifications		$	0.8		$	(0.3	)
	*	These items are included in the computation of net periodic benefit cost. See Note 13, Employee Benefit Plans, for more information.

VARIABLE_INTEREST_ENTITIES_Tab

VARIABLE INTEREST ENTITIES (Tables)	3 Months Ended
	Mar. 31, 2015
AMP Trillium, LLC
Variable interest entities
Schedule of significant assets and liabilities related to variable interest entity	The following table shows the significant assets and liabilities recorded on our balance sheets related to AMP Trillium, LLC:
	(Millions)		March 31, 2015		December 31, 2014
	Assets
	Accounts receivable and accrued unbilled revenues		$	12.1	$	9.5
	Other current assets (1)		2		2
	Investment in AMP Trillium, LLC		5.4		5.5
	Other long-term assets (1)		11.3		11.8
	Liabilities
	Accounts payable		2.7		1.4
	Other current liabilities (2)		2.1		2
	(1)	Relates to notes receivable due from AMP Trillium, LLC.
	(2)	Relates to deferred revenue from the sale of CNG fueling stations to AMP Trillium, LLC.
EVO Trillium, LLC
Variable interest entities
Schedule of significant assets and liabilities related to variable interest entity	The following table shows the significant assets recorded on our balance sheets related to EVO Trillium, LLC:
	(Millions)		March 31, 2015		December 31, 2014
	Assets
	Accounts receivable and accrued unbilled revenues		$	7.6	$	8.8
	Other current assets *		1.1		0.5
	Other long-term assets *		4		1.7
	*	Primarily relates to notes receivable due from EVO Trillium, LLC.

RISK_MANAGEMENT_ACTIVITIES_Tab

RISK MANAGEMENT ACTIVITIES (Tables)	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Assets and liabilities from risk management activities	The following tables show our assets and liabilities from risk management activities at the utilities and IBS:
					March 31, 2015
	(Millions)		Balance Sheet Presentation *		Assets from				Liabilities from
					Risk Management Activities				Risk Management Activities
	Natural gas contracts		Other current		$	0.5			$	28
	Natural gas contracts		Other long-term		0.6				5.7
	FTRs		Other current		0.7				0.1
	Petroleum product contracts		Other current		—				2.1
	Coal contracts		Other current		—				4.3
	Coal contracts		Other long-term		—				3.1
			Other current		1.2				34.5
			Other long-term		0.6				8.8
	Total				$	1.8			$	43.3
	*	We classify assets and liabilities from risk management activities as current or long-term based on the maturities of the underlying contracts.
					31-Dec-14
	(Millions)		Balance Sheet Presentation *		Assets from				Liabilities from
					Risk Management Activities				Risk Management Activities
	Natural gas contracts		Other current		$	1.8			$	37.3
	Natural gas contracts		Other long-term		0.5				5.3
	FTRs		Other current		2.2				0.3
	Petroleum product contracts		Other current		—				2.7
	Petroleum product contracts		Other long-term		—				0.1
	Coal contracts		Other current		—				2.4
	Coal contracts		Other long-term		—				1
			Other current		4				42.7
			Other long-term		0.5				6.4
	Total				$	4.5			$	49.1
	*	We classify assets and liabilities from risk management activities as current or long-term based on the maturities of the underlying contracts.
Potential effect of netting arrangements 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, 2015
	(Millions)		Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements		$	1.8			$	1.2			$	0.6
	Derivative assets not subject to master netting or similar arrangements		—								—
	Total risk management assets		$	1.8							$	0.6
	Derivative liabilities subject to master netting or similar arrangements		$	35.9			$	5.5			$	30.4
	Derivative liabilities not subject to master netting or similar arrangements		7.4								7.4
	Total risk management liabilities		$	43.3							$	37.8
			31-Dec-14
	(Millions)		Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements		$	3.2			$	1.3			$	1.9
	Derivative assets not subject to master netting or similar arrangements		1.3								1.3
	Total risk management assets		$	4.5							$	3.2
	Derivative liabilities subject to master netting or similar arrangements		$	45.7			$	8.8			$	36.9
	Derivative liabilities not subject to master netting or similar arrangements		3.4								3.4
	Total risk management liabilities		$	49.1							$	40.3
Cash collateral positions	The following table shows our cash collateral positions:
	(Millions)		March 31, 2015				31-Dec-14
	Cash collateral provided to others: *
	Related to contracts under master netting or similar arrangements		$	8.9			$	11.6
	Other		1.1				1.1
	*	Cash collateral provided to others is reflected in other current assets.
Notional volumes of outstanding derivative contracts	The notional volumes of outstanding derivative contracts at the utilities and IBS were as follows:
			March 31, 2015						31-Dec-14
	(Millions)		Purchases			Other Transactions			Purchases			Other Transactions
	Natural gas (therms)		669			N/A			1,860.00			N/A
	FTRs (kilowatt-hours)		N/A			2,111.10			N/A			4,287.70
	Petroleum products (barrels)		0.1			N/A			0.1			N/A
	Coal (tons)		2.6			N/A			3			N/A
Unrealized gains (losses) related to 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		2015				2014
	Natural gas		Balance Sheet — Regulatory assets (current)		$	10.9			$	0.9
	Natural gas		Balance Sheet — Regulatory assets (long-term)		(0.6		)		(0.2		)
	Natural gas		Balance Sheet — Regulatory liabilities (current)		(1.5		)		3.4
	Natural gas		Balance Sheet — Regulatory liabilities (long-term)		0.1				(0.4		)
	Natural gas		Income Statement — Operating and maintenance expense		(0.1		)		0.2
	FTRs		Balance Sheet — Regulatory assets (current)		0.2				0.1
	FTRs		Balance Sheet — Regulatory liabilities (current)		(0.4		)		(0.1		)
	Petroleum		Balance Sheet — Regulatory assets (current)		0.4				—
	Petroleum		Income Statement — Operating and maintenance expense		0.4				—
	Coal		Balance Sheet — Regulatory assets (current)		(2.6		)		0.2
	Coal		Balance Sheet — Regulatory assets (long-term)		(2.0		)		0.4
	Coal		Balance Sheet — Regulatory liabilities (long-term)		—				1.6

FAIR_VALUE_Tables

FAIR VALUE (Tables)	3 Months Ended
	Mar. 31, 2015
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, 2015
	(Millions)		Level 1			Level 2			Level 3			Total
	Assets
	Risk Management Assets
	Natural gas contracts		$	0.1		$	1		$	—		$	1.1
	Financial transmission rights (FTRs)		—			—			0.7			0.7
	Total Risk Management Assets		$	0.1		$	1		$	0.7		$	1.8
	Investment in exchange-traded funds		$	112.3		$	—		$	—		$	112.3
	Liabilities
	Risk Management Liabilities
	Natural gas contracts		$	2.3		$	31.4		$	—		$	33.7
	Petroleum product contracts		2.1			—			—			2.1
	FTRs		—			—			0.1			0.1
	Coal contracts		—			1.2			6.2			7.4
	Total Risk Management Liabilities		$	4.4		$	32.6		$	6.3		$	43.3
			31-Dec-14
	(Millions)		Level 1			Level 2			Level 3			Total
	Assets
	Risk Management Assets
	Natural gas contracts		$	—		$	2.3		$	—		$	2.3
	FTRs		—			—			2.2			2.2
	Total Risk Management Assets		$	—		$	2.3		$	2.2		$	4.5
	Investment in exchange-traded funds		$	102.4		$	—		$	—		$	102.4
	Liabilities
	Risk Management Liabilities
	Natural gas contracts		$	4.8		$	31.2		$	6.6		$	42.6
	FTRs		—			—			0.3			0.3
	Petroleum product contracts		2.8			—			—			2.8
	Coal contracts		—			1.2			2.2			3.4
	Total Risk Management Liabilities		$	7.6		$	32.4		$	9.1		$	49.1
Significant unobservable inputs used in the valuation of derivatives categorized in Level 3	The amounts 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, 2015:
			Fair Value (Millions)
			Assets			Liabilities			Valuation Technique		Unobservable Input	Average or Range
	FTRs		$	0.7		$	0.1		Market-based		Forward market prices ($/megawatt-month) (1)	$159.42
	Coal contracts		—			6.2			Market-based		Forward market prices ($/ton) (2)	$9.70 – $12.39
	(1)	Represents forward market prices developed using historical cleared pricing data from MISO.
	(2)	Represents third-party forward market pricing.
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, 2015
	(Millions)		Natural Gas Contracts			FTRs			Coal			Total
									Contracts
	Balance at the beginning of the period		$	(6.6	)	$	1.9		$	(2.2	)	$	(6.9	)
	Net realized losses included in earnings		—			(1.2		)	—			(1.2		)
	Net unrealized losses recorded as regulatory assets or liabilities		—			(0.2		)	(4.3		)	(4.5		)
	Settlements		6.6			0.1			0.3			7
	Balance at the end of the period		$	—		$	0.6		$	(6.2	)	$	(5.6	)
	Three Months Ended March 31, 2014
	(Millions)					FTRs			Coal			Total
									Contracts
	Balance at the beginning of the period					$	1.2		$	(2.5	)	$	(1.3	)
	Net realized gains included in earnings					0.7			—			0.7
	Net unrealized gains recorded as regulatory assets or liabilities					—			2.2			2.2
	Purchases					(0.1		)	—			(0.1		)
	Settlements					(1.3		)	0.6			(0.7		)
	Balance at the end of the period					$	0.5		$	0.3		$	0.8
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, 2015						31-Dec-14
	(Millions)		Carrying Amount			Fair Value			Carrying Amount			Fair Value
	Long-term debt		$	3,081.30		$	3,328.00		$	3,081.30		$	3,271.40
	Preferred stock of subsidiary		51.1			52.3			51.1			51.8

SEGMENTS_OF_BUSINESS_Tables

SEGMENTS OF BUSINESS (Tables)	3 Months Ended
	Mar. 31, 2015
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, 2015
	External revenues	$	839.5		$	295.8		$	—	$	1,135.30		$	—		$	27.9		$	—		$	1,163.20
	Intersegment revenues	2.6			—			—		2.6			—			0.2			(2.8		)	—
	Depreciation and amortization expense	40.6			25			—		65.6			—			9.2			(0.1		)	74.7
	Earnings from equity method investments	—			—			17		17			—			0.5			—			17.5
	Miscellaneous income	0.7			2.8			—		3.5			—			5.1			(2.0		)	6.6
	Interest expense	14.3			10.9			—		25.2			—			15			(2.0		)	38.2
	Provision (benefit) for income taxes	65.9			16.4			6.7		89			—			(10.1		)	—			78.9
	Net income (loss) from continuing operations	97.8			28.6			10.3		136.7			—			(5.5		)	—			131.2
	Discontinued operations	—			—			—		—			(0.8		)	(0.1		)	—			(0.9		)
	Preferred stock dividends of subsidiary	(0.1		)	(0.7		)	—		(0.8		)	—			—			—			(0.8		)
	Net income (loss) attributed to common shareholders	97.7			27.9			10.3		135.9			(0.8		)	(5.6		)	—			129.5
		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-14
	External revenues	$	1,267.60		$	349.2		$	—	$	1,616.80		$	—		$	21.2		$	—		$	1,638.00
	Intersegment revenues	4.4			—			—		4.4			—			0.4			(4.8		)	—
	Depreciation and amortization expense	36.4			25.6			—		62			—			8.7			(0.1		)	70.6
	Earnings from equity method investments	—			—			22.5		22.5			—			0.4			—			22.9
	Miscellaneous income	0.3			3.5			—		3.8			—			5.3			(3.3		)	5.8
	Interest expense	13.4			11.7			—		25.1			—			17.1			(3.3		)	38.9
	Provision (benefit) for income taxes	66.7			18.1			8.8		93.6			—			(11.7		)	—			81.9
	Net income (loss) from continuing operations	99.2			31.8			13.7		144.7			—			(4.5		)	—			140.2
	Discontinued operations	—			—			—		—			13			(0.1		)	—			12.9
	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			13			(4.5		)	—			152.4

PROPOSED_MERGER_WITH_WISCONSIN1

PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION (Details) (USD $)	1 Months Ended
	Jun. 30, 2014
Business Combinations [Abstract]
Number of Wisconsin Energy shares per Integrys Energy Group share	1.128
Cash per share of Integrys Energy Group common stock	$18.58
Integrys Energy Group shareholder's ownership percentage of combined company	28.00%
Wisconsin Energy shareholder's ownership percentage of combined company	72.00%

ACQUISITIONS_Details

ACQUISITIONS (Details) (Alliant Energy Corporation's natural gas distribution business in southeast Minnesota, MERC, Subsequent event, USD $)	1 Months Ended
In Millions, unless otherwise specified	Apr. 30, 2015
Alliant Energy Corporation's natural gas distribution business in southeast Minnesota | MERC | Subsequent event
Acquisitions
Total purchase price	$13.60
Purchase price paid in cash	11
Purchase price not paid in cash	$2.60

DISPOSITIONS_DISCONTINUED_OPER

DISPOSITIONS - DISCONTINUED OPERATIONS (Details) (USD $)	3 Months Ended		1 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Nov. 30, 2014	Dec. 31, 2014	Nov. 01, 2014
Assets and liabilities included in disposal group on balance sheets
Total assets	$51.50			$52.20
Total liabilities	13.6			13.8
Components of discontinued operations recorded in income statements
Discontinued operations, net of tax	-0.9	12.9
IES | IES's retail energy business
Assets and liabilities included in disposal group on balance sheets
Cash and cash equivalents					7.6
Accounts receivable and accrued unbilled revenues, net of reserves					293.4
Accounts receivable and accrued unbilled revenues, reserves					1.8
Inventories					52.2
Current assets from risk management activities					234.8
Other current assets					75.1
Property, plant, and equipment, net of accumulated depreciation					4.5
Accumulated depreciation					16.6
Long-term assets from risk management activities					106.9
Other long-term assets					25.5
Total assets					800
Accounts payable					186.9
Current liabilities from risk management activities					169.7
Accrued taxes					0.8
Other current liabilities					6.7
Long-term liabilities from risk management activities					79.5
Other long-term liabilities					0.3
Total liabilities					443.9
Components of discontinued operations recorded in income statements
Revenues	0	1,289.60
Cost of sales	0	-1,234.80
Operating and maintenance expense	-1.2	-32
Depreciation and amortization expense	0	-0.7
Taxes other than income taxes	-0.2	-1.2
Miscellaneous income	0.1	0.2
Interest expense	0	-0.2
(Loss) income before taxes	-1.3	20.9
Benefit (provision) for income taxes	0.5	-7.9
Discontinued operations, net of tax	-0.8	13
Disclosures related to discontinued operations
Proceeds from sale			331.8
Transition period for services			15 months
Holding Company and Other
Assets and liabilities included in disposal group on balance sheets
Property, plant, and equipment, net of accumulated depreciation	31.1			32.1
Total assets	50.8			51.5
Total liabilities	13.6			13.8
Holding Company and Other | Combined Locks Energy Center
Assets and liabilities included in disposal group on balance sheets
Total assets	0.7			0.7
Components of discontinued operations recorded in income statements
Discontinued operations, net of tax	$0.10

DISPOSITIONS_DISPOSITIONS_EXCL

DISPOSITIONS - DISPOSITIONS EXCLUDING DISCONTINUED OPERATIONS (Details) (USD $)	1 Months Ended
In Millions, unless otherwise specified	Aug. 31, 2014	Mar. 31, 2015	Dec. 31, 2014
Assets and liabilities classified as held for sale on balance sheets
Total assets		$51.50	$52.20
Total liabilities		13.6	13.8
Holding Company and Other
Assets and liabilities classified as held for sale on balance sheets
Property, plant, and equipment, net of accumulated depreciation		31.1	32.1
Equity method investments		18.5	18.2
Other long-term assets		1.2	1.2
Total assets		50.8	51.5
Current liabilities		0.3	0.3
Deferred investment tax credits		4.7	5
Asset retirement obligation		1.1	1.1
Other long-term liabilities		7.5	7.4
Total liabilities		13.6	13.8
Holding Company and Other | PDI Solar Assets
Assets and liabilities classified as held for sale on balance sheets
Accumulated depreciation		22.1	21.1
Electric Utility | UPPCO
Disclosures related to the disposal
Proceeds from sale	$336.70
Electric Utility | UPPCO | Minimum
Disclosures related to the disposal
Transition period for services	18 months
Electric Utility | UPPCO | Maximum
Disclosures related to the disposal
Transition period for services	30 months

CASH_AND_CASH_EQUIVALENTS_CONT

CASH AND CASH EQUIVALENTS CONTINUING OPERATIONS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Noncurrent restricted cash
Rabbi trust funding related to potential change in control	$12.50
Significant noncash transactions
Construction costs funded through accounts payable	134	92.3
ITF fueling station sale financed with note receivable	2.8	0
Equity issued for employee stock ownership plan	$0	$1.70

CASH_AND_CASH_EQUIVALENTS_DISC

CASH AND CASH EQUIVALENTS DISCONTINUED OPERATIONS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Significant noncash transactions
Net unrealized gains on energy contracts	($0.50)	($19.70)
Deferred income taxes and investment tax credits	45.2	90.3
Other	-10.9	1.1
Discontinued operations
Significant noncash transactions
Net unrealized gains on energy contracts	0	19.6
Deferred income taxes and investment tax credits	0	11.5
Other	$1.30	$6.70

INVESTMENT_IN_ATC_INVESTMENT_R

INVESTMENT IN ATC - INVESTMENT ROLL FORWARD (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Changes to investment in ATC
Investment in ATC, balance at beginning of period	$550.60
Add: Earnings from equity method investment	17.5	22.9
Investment in ATC, balance at end of period	556
ATC
Investment in ATC
Equity method investment, ownership interest (as a percent)	34.00%
Changes to investment in ATC
Investment in ATC, balance at beginning of period	536.7	508.4
Add: Earnings from equity method investment	17	22.5
Add: Capital contributions	1.7	5.1
Less: Dividends received	13.6	18.4
Investment in ATC, balance at end of period	541.8	517.6
ATC | Return on equity reduction for MISO transmission owners
Investment in ATC
Requested return on equity (as a percent)	9.15%
Authorized return on equity (as a percent)	12.20%
Reduction in ATC equity earnings related to prior years	$4.80

INVESTMENT_IN_ATC_ATC_INCOME_S

INVESTMENT IN ATC - ATC INCOME STATEMENT AND BALANCE SHEET (Details) (ATC, USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
ATC
Income statement data
Revenues	$152.40	$163.30
Operating expenses	80	78.6
Other expense	24.4	21.6
Net income	48	63.1
Balance sheet data
Current assets	69.4		66.4
Noncurrent assets	3,779.30		3,728.70
Total assets	3,848.70		3,795.10
Current liabilities	325.7		313.1
Long-term debt	1,701		1,701
Other noncurrent liabilities	188.9		163.8
Shareholders' equity	1,633.10		1,617.20
Total liabilities and shareholders' equity	$3,848.70		$3,795.10

INVENTORIES_Details

INVENTORIES (Details) (PGL and NSG, USD $)	Mar. 31, 2015
In Millions, unless otherwise specified
PGL and NSG
Inventories
Temporary LIFO liquidation credit	$33.50

GOODWILL_AND_OTHER_INTANGIBLE_2

GOODWILL AND OTHER INTANGIBLE ASSETS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Goodwill and other intangible assets
Changes to the carrying amount of goodwill	$0	$0
Total intangible assets, gross carrying amount	45.5		45.1
Total intangible assets, net	32.3		33.2
Amortized intangible assets
Amortized intangible assets, gross carrying amount	34.9		34.9
Accumulated amortization of intangible assets	-13.2		-11.9
Amortized intangible assets, net	21.7		23
Amortization for the next five years
Future amortization period	5 years
Regulatory assets
Amortized intangible assets
Amortization	0.3	0
Amortization for the next five years
Amortization, 2015	1
Amortization, 2016	1
Amortization, 2017	0.5
Amortization, 2018	0
Amortization, 2019	0
Cost of sales
Amortized intangible assets
Amortization	0.3	0.3
Amortization for the next five years
Amortization, 2015	1.1
Amortization, 2016	0.9
Amortization, 2017	0.9
Amortization, 2018	0.8
Amortization, 2019	0.6
Depreciation and amortization expense
Amortized intangible assets
Amortization	0.7	0.7
Amortization for the next five years
Amortization, 2015	3
Amortization, 2016	2.9
Amortization, 2017	2.4
Amortization, 2018	1.9
Amortization, 2019	1.9
Trade name | MGU
Unamortized intangible assets
Unamortized intangible assets, carrying amount	5.2		5.2
Trade name | Trillium
Unamortized intangible assets
Unamortized intangible assets, carrying amount	3.5		3.5
Trade name | Pinnacle
Unamortized intangible assets
Unamortized intangible assets, carrying amount	1.5		1.5
Other unamortized intangible assets
Unamortized intangible assets
Unamortized intangible assets, carrying amount	0.4		0
Contractual service agreements
Amortized intangible assets
Amortized intangible assets, gross carrying amount	15.6		15.6
Accumulated amortization of intangible assets	-5.1		-4.3
Amortized intangible assets, net	10.5		11.3
Weighted-average amortization period	4 years
Customer-owned equipment modifications
Amortized intangible assets
Amortized intangible assets, gross carrying amount	4		4
Accumulated amortization of intangible assets	-1.2		-1.2
Amortized intangible assets, net	2.8		2.8
Weighted-average amortization period	9 years
Intellectual property
Amortized intangible assets
Amortized intangible assets, gross carrying amount	3.4		3.4
Accumulated amortization of intangible assets	-0.9		-0.8
Amortized intangible assets, net	2.5		2.6
Weighted-average amortization period	7 years
Nonregulated easements
Amortized intangible assets
Amortized intangible assets, gross carrying amount	3.9		3.9
Accumulated amortization of intangible assets	-1.5		-1.4
Amortized intangible assets, net	2.4		2.5
Weighted-average amortization period	9 years
Compressed natural gas fueling contract assets
Amortized intangible assets
Amortized intangible assets, gross carrying amount	5.6		5.6
Accumulated amortization of intangible assets	-3.8		-3.6
Amortized intangible assets, net	1.8		2
Weighted-average amortization period	6 years
Customer-related
Amortized intangible assets
Amortized intangible assets, gross carrying amount	1.9		1.9
Accumulated amortization of intangible assets	-0.4		-0.3
Amortized intangible assets, net	1.5		1.6
Weighted-average amortization period	12 years
Other amortized intangible assets
Amortized intangible assets
Amortized intangible assets, gross carrying amount	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 BORROWINGS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Short-term borrowings
Short-term borrowings outstanding	$133.30		$317.60
Commercial paper
Short-term borrowings
Short-term borrowings outstanding	133.3		317.6
Average interest rate (as a percent)	0.37%		0.36%
Average amount of commercial paper borrowings outstanding	$189.50	$247.10

SHORTTERM_DEBT_AND_LINES_OF_CR3

SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) (USD $)	1 Months Ended
In Millions, unless otherwise specified	Apr. 30, 2015	Mar. 31, 2015	Dec. 31, 2014
Short-term borrowings
Total short-term credit capacity		$1,250	$1,250
Letters of credit issued inside credit facilities		0.7	3.4
Short-term borrowings outstanding		133.3	317.6
Available capacity under existing agreements		1,116	929
Revolving credit facility maturing on May 8, 2019 | Integrys Energy Group, Inc.
Short-term borrowings
Total short-term credit capacity		465	465
Revolving credit facility maturing on May 8, 2019 | Integrys Energy Group, Inc. | Subsequent event
Short-term borrowings
Decrease in credit facility	200
Revolving credit facility maturing on May 8, 2019 | WPS
Short-term borrowings
Total short-term credit capacity		135	135
Revolving credit facility maturing on June 13, 2017 | Integrys Energy Group, Inc.
Short-term borrowings
Total short-term credit capacity		285	285
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		$133.30	$317.60

INCOME_TAXES_Details

INCOME TAXES (Details)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Income Tax Disclosure [Abstract]
Effective tax rate (as a percent)	37.60%	36.90%
Federal statutory tax rate (as a percent)	35.00%	35.00%

COMMITMENTS_AND_CONTINGENCIES_1

COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) (Regulated operations, USD $)	Mar. 31, 2015
In Millions, unless otherwise specified
Minimum future commitments for purchase obligations
Total Amounts Committed	$1,626.50
2015	265.2
2016	249.2
2017	221.2
2018	167.6
2019	120.5
Later Years	602.8
Natural gas utility supply and transportation | Natural Gas Utility
Minimum future commitments for purchase obligations
Total Amounts Committed	664.6
2015	128.8
2016	171.7
2017	134.4
2018	79.6
2019	52.3
Later Years	97.8
Purchased power | Electric Utility
Minimum future commitments for purchase obligations
Total Amounts Committed	806.1
2015	92.1
2016	42.7
2017	53.3
2018	55.9
2019	57.1
Later Years	505
Coal supply and transportation | Electric Utility
Minimum future commitments for purchase obligations
Total Amounts Committed	155.8
2015	44.3
2016	34.8
2017	33.5
2018	32.1
2019	11.1
Later Years	$0

COMMITMENTS_AND_CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) (USD $)	1 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2013	Jun. 30, 2013	Oct. 31, 2014	Mar. 31, 2015
				site
Manufactured gas plant remediation | Natural Gas Utility
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				$573
Environmental remediation cash expenditures not yet recovered in rates				43.1
Regulatory assets recorded for cash and estimated future remediation expenditures, net of insurance recoveries received				616.1
WPS | Weston and Pulliam plants | Electric Utility
Air Permitting Violation Claims
Beneficial environmental project amount	6
Civil penalty and/or legal fees	1.2
WPS | Columbia and Edgewater jointly-owned plants | Electric Utility
Air Permitting Violation Claims
Beneficial environmental project amount		1.3
Civil penalty and/or legal fees		$0.40
WPS | Sulfur dioxide and nitrogen oxide | Electric Utility
Mercury and Interstate Air Quality Rules
EPA change to compliance deadline for Cross State Air Pollution Rule			3 years
WPS | Clean Water Act rule | Electric Utility
Clean Water Act Rule
Number of units equipped with cooling towers				2

GUARANTEES_Details

GUARANTEES (Details) (USD $)	Mar. 31, 2015
In Millions, unless otherwise specified
Guarantees
Total guarantees	$306.90
Guarantees expiring in less than 1 year	156
Guarantees expiring within 1 to 3 years	0.9
Guarantees with expiration over 3 years	150
Guarantees supporting commodity transactions of subsidiaries
Guarantees
Total guarantees	162.5
Guarantees expiring in less than 1 year	91.2
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	71.3
Guarantees supporting commodity transactions of subsidiaries | IBS
Guarantees
Total guarantees	5
Guarantees supporting commodity transactions of subsidiaries | PDI
Guarantees
Total guarantees	5
Guarantees supporting commodity transactions of subsidiaries | ITF
Guarantees
Total guarantees	0.4
Guarantees supporting commodity transactions of subsidiaries | MERC
Guarantees
Total guarantees	108.9
Guarantees supporting commodity transactions of subsidiaries | MGU
Guarantees
Total guarantees	43.2
Standby letters of credit
Guarantees
Total guarantees	1.2
Guarantees expiring in less than 1 year	1.1
Guarantees expiring within 1 to 3 years	0.1
Guarantees with expiration over 3 years	0
Surety bonds
Guarantees
Total guarantees	25.1
Guarantees expiring in less than 1 year	25.1
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	0
Guarantees temporarily retained related to the sale of IES's retail energy business
Guarantees
Total guarantees	55.7
Guarantees expiring in less than 1 year	38.6
Guarantees expiring within 1 to 3 years	0.8
Guarantees with expiration over 3 years	16.3
Guarantees supporting commodity transactions temporarily retained by Integrys Energy Group | IES's retail energy business
Guarantees
Total guarantees	52.1
Standby letters of credit temporarily retained by Integrys Energy Group | IES's retail energy business
Guarantees
Total guarantees	1.2
Surety bonds temporarily retained by Integrys Energy Group | IES's retail energy business
Guarantees
Total guarantees	2.1
Guarantees related to the sale of WPS Beaver Falls Generation, LLC temporarily retained by Integrys Energy Group | WPS Beaver Falls Generation, LLC
Guarantees
Total guarantees	0.3
Maximum exposure for guarantees related to open transactions | IES's retail energy business
Guarantees
Total guarantees	31.5
Other guarantees
Guarantees
Total guarantees	62.4
Guarantees expiring in less than 1 year	0
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	62.4
Other guarantees | IES's Texas retail marketing business
Guarantees
Total guarantees	10
Other guarantees | PDI
Guarantees
Total guarantees	34.2
Other guarantees | ITF
Guarantees
Total guarantees	11.2
Other indemnifications primarily for workers compensation coverage
Guarantees
Total guarantees	$7

EMPLOYEE_BENEFIT_PLANS_Details

EMPLOYEE BENEFIT PLANS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Rabbi trust funding during 2014 related to potential change in control			$132.20
Pension Benefits
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Service cost	7.6	6.6
Interest cost	17	19.7
Expected return on plan assets	-26.9	-28.9
Loss on plan settlement	0.5	0
Amortization of prior service cost (credit)	0.1	0.2
Amortization of net actuarial loss	10.5	8.4
Net periodic benefit cost	8.8	6
Contributions to the plans	2.8
Expected contributions to the plans during the remainder of fiscal year	6.3
Expected contributions to the plans during the remainder of the fiscal year from the Rabbi trust	7
Assets transferred from the Rabbi Trust in the current year for certain nonqualified pension plan payments	2.2
Other Postretirement Benefits
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Service cost	5.8	5.9
Interest cost	5.3	7.1
Expected return on plan assets	-7.9	-8.8
Loss on plan settlement	0	0
Amortization of prior service cost (credit)	-2.6	-1.3
Amortization of net actuarial loss	1.1	0.7
Net periodic benefit cost	1.7	3.6
Contributions to the plans	0.1
Expected contributions to the plans during the remainder of fiscal year	$8.90

STOCKBASED_COMPENSATION_STOCKB

STOCK-BASED COMPENSATION – STOCK-BASED COMPENSATION EXPENSE (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Information related to share based awards
Total stock-based compensation expense	$4.20	$3.50
Deferred income tax benefit	1.7	1.4
Stock-based compensation cost capitalized	0	0
Stock options
Information related to share based awards
Total stock-based compensation expense	0	0.3
Performance stock rights
Information related to share based awards
Total stock-based compensation expense	0.6	0.5
Restricted Share Units
Information related to share based awards
Total stock-based compensation expense	3.4	2.5
Nonemployee director deferred stock units
Information related to share based awards
Total stock-based compensation expense	$0.20	$0.20

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, 2015	Mar. 31, 2014
Stock options
Weighted-average fair value
Weighted-average fair value per stock option granted (in dollars per share)		$6.70
Stock Options
Outstanding, at the beginning of the period (in shares)	134,017
Exercised (in shares)	-45,297
Outstanding, at the end of the period (in shares)	88,720
Exercisable at the end of the period (in shares)	53,057
Weighted-Average Exercise Price Per Share
Outstanding at the beginning of the period (in dollars per share)	$54.31
Exercised (in dollars per share)	$53.32
Outstanding at the end of the period (in dollars per share)	$54.81
Exercisable at the end of the period (in dollars per share)	$54.84
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 11 months
Aggregate Intrinsic Value
Outstanding at the end of the period (in dollars)	$1.50
Exercisable at the end of the period (in dollars)	0.9
Additional disclosures
Granted (in shares)	0
Proceeds from stock option exercises	$2.70

STOCKBASED_COMPENSATION_PERFOR

STOCK-BASED COMPENSATION – PERFORMANCE STOCK RIGHTS (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Performance stock rights
Assumptions incorporated into the valuation models
Risk-free interest rate, minimum (as a percent)	0.42%
Risk-free interest rate, maximum (as a percent)	0.63%
Expected volatility, minimum (as a percent)	18.00%
Expected volatility, maximum (as a percent)	19.00%
Performance Stock Rights
Distributed (in shares)		0
Granted (in shares)	0
Additional disclosures
Total intrinsic value of shares distributed during the period	$3.10
Compensation cost not yet recognized	$3.30
Weighted-average period over which compensation cost is to be recognized	1 year 5 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)	5.25%
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)	68,263
Distributed (in shares)	-38,639
Adjustment for payout (in shares)	12,751
Outstanding at the end of period (in shares)	42,375
Weighted-Average Fair Value
Outstanding at the beginning of the period (in dollars per share)	$58.54
Distributed (in dollars per share)	$78.37
Granted (in dollars per share)		44.28
Adjustment for payout (in dollars per share)	$78.37
Outstanding at the end of the period (in dollars per share)	$46.42
Performance Stock Rights Accounted For As Liability Awards
Performance Stock Rights
Outstanding at the beginning of the period (in shares)	170,308
Distributed (in shares)	-1,746
Adjustment for payout (in shares)	831
Outstanding at the end of period (in shares)	169,393
Weighted-Average Fair Value
Outstanding at the end of the period, fair value as of the reporting date (in dollars per share)	$106.95

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, 2015	Mar. 31, 2014
Restricted Share Units
Restricted Share Unit Awards
Outstanding at the beginning of the period (in shares)	427,305
Granted (in shares)	224,784
Dividend equivalents (in shares)	4,437
Vested and released (in shares)	-166,545
Forfeited (in shares)	-530
Outstanding at the end of period (in shares)	489,451
Weighted-Average Grant Date Fair Value
Outstanding at the beginning of the period (in dollars per share)	$54.45
Granted (in dollars per share)	$77.17	$55.23
Dividend equivalents (in dollars per share)	$65.31
Vested and released (in dollars per share)	$53.49
Forfeited (in dollars per share)	$52.35
Outstanding at the end of the period (in dollars per share)	$65.31
Additional disclosures
Total intrinsic value of restricted share units vested and released	$12.80	$11.10
Tax benefit realized from the vesting and release of restricted share units	5.1	4.4
Compensation cost not yet recognized	$20.40
Weighted-average period over which compensation cost is to be recognized	2 years 2 months

COMMON_EQUITY_CHANGES_TO_ISSUE

COMMON EQUITY - CHANGES TO ISSUED COMMON STOCK (Details)	3 Months Ended
	Mar. 31, 2015
Stockholders' Equity Note [Abstract]
Changes to Common Stock Issued	0

COMMON_EQUITY_RECONCILIATION_O

COMMON EQUITY - RECONCILIATION OF COMMON SHARES ISSUED AND OUTSTANDING (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Reconciliation of Shares Issued and Outstanding
Common stock issued (in shares)	79,963,091	79,963,091
Deferred compensation rabbi trust (in shares)	428,920	428,920
Total common shares outstanding	79,534,171	79,534,171
Average cost of shares in the rabbi trust (in dollars per share)	$48.73	$48.73

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, 2015	Mar. 31, 2014
Numerator:
Net income from continuing operations	$131.20	$140.20
Discontinued operations, net of tax	-0.9	12.9
Preferred stock dividends of subsidiary	-0.8	-0.8
Noncontrolling interest in subsidiaries	0	0.1
Net income attributed to common shareholders	129.5	152.4
Net income attributed to common shareholders — diluted	128.9	152.4
Denominator:
Average shares of common stock — basic	80.2	80.2
Average shares of common stock - diluted	80.8	80.5
Earnings per common share
Basic (in dollars per share)	$1.61	$1.90
Diluted (in dollars per share)	$1.60	$1.89
Stock-based compensation
Denominator:
Effect of dilutive securities	0.4	0.3
Deferred compensation
Numerator:
Effect of dilutive securities	($0.60)	$0
Denominator:
Effect of dilutive securities	0.2	0

COMMON_EQUITY_ANTIDILUTIVE_SEC

COMMON EQUITY - ANTIDILUTIVE SECURITIES (Details)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Stock-based compensation
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted-average outstanding securities that had an anti-dilutive effect	0	0.7
Deferred compensation
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted-average outstanding securities that had an anti-dilutive effect	0	0.3

COMMON_EQUITY_DIVIDEND_RESTRIC

COMMON EQUITY - DIVIDEND RESTRICTIONS (Details) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Dividend Payment Restrictions
Maximum debt to capitalization ratio required to be maintained (as a percent)	65.00%
Total restricted net assets for consolidated subsidiaries	$1,872.60
Equity in undistributed earnings of 50% or less owned investees accounted for by the equity method	$158.10
Dividends per common share declared (in dollars per share)	$0.68	$0.68
Maximum
Dividend Payment Restrictions
Equity method investment, ownership interest (as a percent)	50.00%
Cumulative period of interest payment deferral on Junior Subordinated Notes	10 years
Dividends per common share declared (in dollars per share)	$0.68
Minimum
Dividend Payment Restrictions
Number of periods for which interest payments can be deferred on Junior Subordinated Notes	1
PGL
Dividend Payment Restrictions
Maximum debt to capitalization ratio required to be maintained (as a percent)	65.00%
WPS
Dividend Payment Restrictions
Maximum 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, 2015
Capital Transactions with Subsidiaries
Dividends to parent	$50
Return of capital to parent	23.5
Equity contributions from parent	2.7
WPS Investments, LLC
Capital Transactions with Subsidiaries
Ownership interest (as a percent)	89.06%
ITF
Capital Transactions with Subsidiaries
Dividends to parent	0
Return of capital to parent	0
Equity contributions from parent	1
MERC
Capital Transactions with Subsidiaries
Dividends to parent	0
Return of capital to parent	10.5
Equity contributions from parent	0
MGU
Capital Transactions with Subsidiaries
Dividends to parent	0
Return of capital to parent	13
Equity contributions from parent	0
NSG
Capital Transactions with Subsidiaries
Dividends to parent	7.5
Return of capital to parent	0
Equity contributions from parent	0
WPS
Capital Transactions with Subsidiaries
Dividends to parent	28.8
Return of capital to parent	0
Equity contributions from parent	0
WPS | WPS Investments, LLC
Capital Transactions with Subsidiaries
Ownership interest (as a percent)	10.94%
WPS Investments, LLC
Capital Transactions with Subsidiaries
Dividends to parent	13.7
Return of capital to parent	0
Equity contributions from parent	$1.70

ACCUMULATED_OTHER_COMPREHENSIV2

ACCUMULATED OTHER COMPREHENSIVE LOSS - ROLL FORWARD (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Changes to accumulated other comprehensive loss, net of tax
Accumulated other comprehensive loss, balance at beginning of period	($27.60)	($23.20)
Other comprehensive loss before reclassifications		-0.1
Amounts reclassified out of accumulated other comprehensive loss	0.8	-0.3
Other comprehensive income (loss), net of tax	0.8	-0.4
Accumulated other comprehensive loss, balance at end of period	-26.8	-23.6
Cash flow hedges
Changes to accumulated other comprehensive loss, net of tax
Accumulated other comprehensive loss, balance at beginning of period	-3.2	-3.1
Other comprehensive loss before reclassifications		0
Amounts reclassified out of accumulated other comprehensive loss	0.1	-0.6
Other comprehensive income (loss), net of tax		-0.6
Accumulated other comprehensive loss, balance at end of period	-3.1	-3.7
Defined benefit plans
Changes to accumulated other comprehensive loss, net of tax
Accumulated other comprehensive loss, balance at beginning of period	-24.4	-20.1
Other comprehensive loss before reclassifications		-0.1
Amounts reclassified out of accumulated other comprehensive loss	0.7	0.3
Other comprehensive income (loss), net of tax		0.2
Accumulated other comprehensive loss, balance at end of period	($23.70)	($19.90)

ACCUMULATED_OTHER_COMPREHENSIV3

ACCUMULATED OTHER COMPREHENSIVE LOSS - RECLASSIFICATIONS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Amount reclassified out of accumulated other comprehensive loss
Interest expense	$38.20	$38.90
Total before tax	-210.1	-222.1
Tax expense	-78.9	-81.9
Net of tax	-131.2	-140.2
Amount reclassified
Amount reclassified out of accumulated other comprehensive loss
Net of tax	0.8	-0.3
Losses (gains) on cash flow hedges | Amount reclassified
Amount reclassified out of accumulated other comprehensive loss
Tax expense	0.1	0.9
Net of tax	0.1	-0.6
Losses (gains) on cash flow hedges | Interest rate hedges | Amount reclassified
Amount reclassified out of accumulated other comprehensive loss
Interest expense	0.2	0.3
Defined benefit plans | Amount reclassified
Amount reclassified out of accumulated other comprehensive loss
Amortization of prior service costs (credits)	0.3	-0.1
Amortization of net actuarial losses	0.9	0.7
Total before tax	1.2	0.6
Tax expense	0.5	0.3
Net of tax	$0.70	$0.30

VARIABLE_INTEREST_ENTITIES_Det

VARIABLE INTEREST ENTITIES (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Variable interest entities
Accounts receivable and accrued unbilled revenues	720.8	$699.80
Other current assets	43	57.4
Investment in AMP Trillium, LLC	556	550.6
Other long-term assets	262.2	272.6
Accounts payable	414.6	490.7
Other current liabilities	282.1	261
AMP Trillium, LLC
Variable interest entities
Accounts receivable and accrued unbilled revenues	12.1	9.5
Other current assets	2	2
Investment in AMP Trillium, LLC	5.4	5.5
Other long-term assets	11.3	11.8
Accounts payable	2.7	1.4
Other current liabilities	2.1	2
AMP Trillium, LLC | Co-venturer
Variable interest entities
Variable interest entity, ownership interest (as a percent)	70.00%
AMP Trillium, LLC | ITF
Variable interest entities
Variable interest entity, ownership interest (as a percent)	30.00%
EVO Trillium, LLC
Variable interest entities
Accounts receivable and accrued unbilled revenues	7.6	8.8
Other current assets	1.1	0.5
Other long-term assets	4	$1.70
EVO Trillium, LLC | Co-venturer
Variable interest entities
Variable interest entity, ownership interest (as a percent)	85.00%
EVO Trillium, LLC | ITF
Variable interest entities
Variable interest entity, ownership interest (as a percent)	15.00%

RISK_MANAGEMENT_ACTIVITIES_RIS

RISK MANAGEMENT ACTIVITIES - RISK MANAGEMENT ASSETS AND LIABILITIES (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Derivative Asset [Abstract]
Risk Management Assets	$1.80	$4.50
Derivative Liability [Abstract]
Risk Management Liabilities	43.3	49.1
Designated as hedging instrument
Derivative, Number of Instruments Held [Abstract]
Number of derivative instruments held	0
Non-hedge derivatives
Derivative Asset [Abstract]
Other current assets from risk management activities	1.2	4
Other long-term assets from risk management activities	0.6	0.5
Risk Management Assets	1.8	4.5
Derivative Liability [Abstract]
Other current liabilities from risk management activities	34.5	42.7
Other long-term liabilities from risk management activities	8.8	6.4
Risk Management Liabilities	43.3	49.1
Non-hedge derivatives | Natural gas contracts
Derivative Asset [Abstract]
Other current assets from risk management activities	0.5	1.8
Other long-term assets from risk management activities	0.6	0.5
Derivative Liability [Abstract]
Other current liabilities from risk management activities	28	37.3
Other long-term liabilities from risk management activities	5.7	5.3
Non-hedge derivatives | FTRs
Derivative Asset [Abstract]
Other current assets from risk management activities	0.7	2.2
Derivative Liability [Abstract]
Other current liabilities from risk management activities	0.1	0.3
Non-hedge derivatives | Petroleum product contracts
Derivative Asset [Abstract]
Other current assets from risk management activities	0	0
Other long-term assets from risk management activities		0
Derivative Liability [Abstract]
Other current liabilities from risk management activities	2.1	2.7
Other long-term liabilities from risk management activities		0.1
Non-hedge derivatives | Coal contracts
Derivative Asset [Abstract]
Other current assets from risk management activities	0	0
Other long-term assets from risk management activities	0	0
Derivative Liability [Abstract]
Other current liabilities from risk management activities	4.3	2.4
Other long-term liabilities from risk management activities	$3.10	$1

RISK_MANAGEMENT_ACTIVITIES_NET

RISK MANAGEMENT ACTIVITIES - NETTING ARRANGEMENTS (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Assets
Derivative assets subject to master netting or similar arrangements, gross amount	$1.80	$3.20
Potential effects of netting, including cash collateral	1.2	1.3
Derivative assets subject to master netting or similar arrangements, net amount	0.6	1.9
Derivative assets not subject to master netting or similar arrangements	0	1.3
Risk Management Assets	1.8	4.5
Total Risk Management Assets, Net Amount	0.6	3.2
Liabilities
Derivative liabilities subject to master netting or similar arrangements, gross amount	35.9	45.7
Potential effects of netting, including cash collateral	5.5	8.8
Derivative liabilities subject to master netting or similar arrangements, net amount	30.4	36.9
Derivative liabilities not subject to master netting or similar arrangement	7.4	3.4
Risk Management Liabilities	43.3	49.1
Total Risk Management Liabilities, Net Amount	$37.80	$40.30

RISK_MANAGEMENT_ACTIVITIES_CAS

RISK MANAGEMENT ACTIVITIES - CASH COLLATERAL AND CREDIT-RISK RELATED CONTINGENT FEATURES (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Cash collateral
Cash collateral provided to others, related to contracts under master netting or similar arrangements	$8.90	$11.60
Cash collateral provided to others, other	1.1	1.1
Credit-risk related contingent features
Aggregate fair value of derivative instruments with credit risk-related contingent features that were in a liability position	31.4	31.3
Collateral that would have been required	$30.10	$27.10

RISK_MANAGEMENT_ACTIVITIES_NOT

RISK MANAGEMENT ACTIVITIES - NOTIONAL VOLUMES (Details) (Non-hedge derivatives)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2013
	MMBTU	MMBTU
Natural gas contracts | Purchases
Risk management activities
Notional volume of outstanding derivative contracts (mmbtu or kwh)	66,900,000	186,000,000
FTRs | Other transactions
Risk management activities
Notional volume of outstanding derivative contracts (mmbtu or kwh)	2,111,100,000	4,287,700,000
Petroleum product contracts | Purchases
Risk management activities
Notional volume of outstanding derivative contracts (barrels)	100,000	100,000
Coal contracts | Purchases
Risk management activities
Notional volume of outstanding derivative contracts (tons)	2,600,000	3,000,000

RISK_MANAGEMENT_ACTIVITIES_UNR

RISK MANAGEMENT ACTIVITIES - UNREALIZED GAINS AND LOSSES (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Natural gas contracts | Income Statement - Operating and maintenance expense
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	($0.10)	$0.20
Natural gas contracts | Balance Sheet - Regulatory assets (current)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	10.9	0.9
Natural gas contracts | Balance Sheet - Regulatory assets (long-term)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-0.6	-0.2
Natural gas contracts | Balance Sheet - Regulatory liabilities (current)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-1.5	3.4
Natural gas contracts | Balance Sheet - Regulatory liabilities (long-term)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	0.1	-0.4
FTRs | Balance Sheet - Regulatory assets (current)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	0.2	0.1
FTRs | Balance Sheet - Regulatory liabilities (current)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-0.4	-0.1
Petroleum product contracts | Income Statement - Operating and maintenance expense
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	0.4	0
Petroleum product contracts | Balance Sheet - Regulatory assets (current)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	0.4	0
Coal contracts | Balance Sheet - Regulatory assets (current)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-2.6	0.2
Coal contracts | Balance Sheet - Regulatory assets (long-term)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-2	0.4
Coal contracts | Balance Sheet - Regulatory liabilities (long-term)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	$0	$1.60

FAIR_VALUE_ASSETS_AND_LIABILIT

FAIR VALUE - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Assets
Risk Management Assets	$1.80		$4.50
Liabilities
Risk Management Liabilities	43.3		49.1
Fair Value, Assets and Liabilities Transfers Between the Levels of the Fair Value Hierarchy [Abstract]
Fair Value Transfers, Amount	0	0
Fair value measurements on a recurring basis | Holding Company and Other | Level 1
Assets
Investment in Exchange-Traded Funds	112.3		102.4
Fair value measurements on a recurring basis | Holding Company and Other | Level 2
Assets
Investment in Exchange-Traded Funds	0		0
Fair value measurements on a recurring basis | Holding Company and Other | Level 3
Assets
Investment in Exchange-Traded Funds	0		0
Fair value measurements on a recurring basis | Holding Company and Other | Total, Fair value
Assets
Investment in Exchange-Traded Funds	112.3		102.4
Fair value measurements on a recurring basis | Utility segments | Level 1
Assets
Risk Management Assets	0.1		0
Liabilities
Risk Management Liabilities	4.4		7.6
Fair value measurements on a recurring basis | Utility segments | Level 2
Assets
Risk Management Assets	1		2.3
Liabilities
Risk Management Liabilities	32.6		32.4
Fair value measurements on a recurring basis | Utility segments | Level 3
Assets
Risk Management Assets	0.7		2.2
Liabilities
Risk Management Liabilities	6.3		9.1
Fair value measurements on a recurring basis | Utility segments | Total, Fair value
Assets
Risk Management Assets	1.8		4.5
Liabilities
Risk Management Liabilities	43.3		49.1
Fair value measurements on a recurring basis | Utility segments | Natural gas contracts | Level 1
Assets
Risk Management Assets	0.1		0
Liabilities
Risk Management Liabilities	2.3		4.8
Fair value measurements on a recurring basis | Utility segments | Natural gas contracts | Level 2
Assets
Risk Management Assets	1		2.3
Liabilities
Risk Management Liabilities	31.4		31.2
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		6.6
Fair value measurements on a recurring basis | Utility segments | Natural gas contracts | Total, Fair value
Assets
Risk Management Assets	1.1		2.3
Liabilities
Risk Management Liabilities	33.7		42.6
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	0.7		2.2
Liabilities
Risk Management Liabilities	0.1		0.3
Fair value measurements on a recurring basis | Utility segments | FTRs | Total, Fair value
Assets
Risk Management Assets	0.7		2.2
Liabilities
Risk Management Liabilities	0.1		0.3
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Level 1
Liabilities
Risk Management Liabilities	2.1		2.8
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Level 2
Liabilities
Risk Management Liabilities	0		0
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Level 3
Liabilities
Risk Management Liabilities	0		0
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Total, Fair value
Liabilities
Risk Management Liabilities	2.1		2.8
Fair value measurements on a recurring basis | Utility segments | Coal contracts | Level 1
Liabilities
Risk Management Liabilities	0		0
Fair value measurements on a recurring basis | Utility segments | Coal contracts | Level 2
Liabilities
Risk Management Liabilities	1.2		1.2
Fair value measurements on a recurring basis | Utility segments | Coal contracts | Level 3
Assets
Risk Management Assets	0
Liabilities
Risk Management Liabilities	6.2		2.2
Fair value measurements on a recurring basis | Utility segments | Coal contracts | Total, Fair value
Liabilities
Risk Management Liabilities	$7.40		$3.40

FAIR_VALUE_SIGNIFICANT_UNOBSER

FAIR VALUE - SIGNIFICANT UNOBSERVABLE INPUTS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Significant internally-developed unobservable inputs
Risk Management Assets	$1.80	$4.50
Risk Management Liabilities	43.3	49.1
Fair value measurements on a recurring basis | Utility segments | Level 3
Significant internally-developed unobservable inputs
Risk Management Assets	0.7	2.2
Risk Management Liabilities	6.3	9.1
Fair value measurements on a recurring basis | Utility segments | Level 3 | FTRs
Significant internally-developed unobservable inputs
Risk Management Assets	0.7	2.2
Risk Management Liabilities	0.1	0.3
Fair value measurements on a recurring basis | Utility segments | Level 3 | FTRs | Valuation Technique: Market-based | Weighted Average
Significant internally-developed unobservable inputs
Forward market prices	159.42
Fair value measurements on a recurring basis | Utility segments | Level 3 | Coal contracts
Significant internally-developed unobservable inputs
Risk Management Assets	0
Risk Management Liabilities	$6.20	$2.20
Fair value measurements on a recurring basis | Utility segments | Level 3 | Coal contracts | Valuation Technique: Market-based | Minimum
Significant internally-developed unobservable inputs
Forward market prices	9.7
Fair value measurements on a recurring basis | Utility segments | Level 3 | Coal contracts | Valuation Technique: Market-based | Maximum
Significant internally-developed unobservable inputs
Forward market prices	12.39

FAIR_VALUE_LEVEL_3_RECONCILIAT

FAIR VALUE - LEVEL 3 RECONCILIATION (Details) (Utility segments, USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
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	($6.90)	($1.30)
Net realized gains (losses) included in earnings	-1.2	0.7
Net unrealized gains (losses) recorded as regulatory assets or liabilities	-4.5	2.2
Purchases		-0.1
Settlements	7	-0.7
Balance at the end of the period	-5.6	0.8
Impact on earnings of unrealized gains (losses) on level 3 instruments	0	0
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	-6.6
Net realized gains (losses) included in earnings	0
Net unrealized gains (losses) recorded as regulatory assets or liabilities	0
Settlements	6.6
Balance at the end of the period	0
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	1.9	1.2
Net realized gains (losses) included in earnings	-1.2	0.7
Net unrealized gains (losses) recorded as regulatory assets or liabilities	-0.2	0
Purchases		-0.1
Settlements	0.1	-1.3
Balance at the end of the period	0.6	0.5
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	-2.2	-2.5
Net realized gains (losses) included in earnings	0	0
Net unrealized gains (losses) recorded as regulatory assets or liabilities	-4.3	2.2
Purchases		0
Settlements	0.3	0.6
Balance at the end of the period	($6.20)	$0.30

FAIR_VALUE_FINANCIAL_INSTRUMEN

FAIR VALUE - FINANCIAL INSTRUMENTS NOT RECORDED AT FAIR VALUE (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
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	3,081.30	3,081.30
Preferred stock	51.1	51.1
Fair value
Carrying value and estimated fair value of financial instruments
Long-term Debt	3,328	3,271.40
Preferred stock	$52.30	$51.80

REGULATORY_ENVIRONMENT_Details

REGULATORY ENVIRONMENT (Details) (USD $)	1 Months Ended		3 Months Ended	12 Months Ended	1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Mar. 31, 2015	Dec. 31, 2014	Nov. 30, 2013	Feb. 28, 2015	Jan. 31, 2015	Oct. 31, 2014	Apr. 30, 2015
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | WPS
Regulatory Environment
Approved return on common equity percent reflected in rates of customers	10.20%
Approved percent of capital structure composed of common equity	50.28%
Public Service Commission of Wisconsin (PSCW) | 2014 Rates | WPS
Regulatory Environment
Approved return on common equity percent reflected in rates of customers		10.20%
Approved percent of capital structure composed of common equity		50.14%
Public Service Commission of Wisconsin (PSCW) | Retail electric rates | 2015 Rates | WPS
Regulatory Environment
Approved annual increase (decrease) in rates for customers	24.6
Costs of fuel for electric generation	42
Change in decoupling amounts to be collected from (refunded to) customers in rates			-9
Customer recoveries (refunds) related to decoupling			-4
Percentage price variance from rate case-approved fuel and purchased power costs before deferral is required	2.00%			2.00%
Public Service Commission of Wisconsin (PSCW) | Retail electric rates | 2014 Rates | WPS
Regulatory Environment
Approved annual increase (decrease) in rates for customers		-12.8
Customer recoveries (refunds) related to decoupling				-13
Public Service Commission of Wisconsin (PSCW) | Retail natural gas rates | 2015 Rates | WPS
Regulatory Environment
Approved annual increase (decrease) in rates for customers	-15.4
Change in decoupling amounts to be collected from (refunded to) customers in rates			-16
Customer recoveries (refunds) related to decoupling			-8
Public Service Commission of Wisconsin (PSCW) | Retail natural gas rates | 2014 Rates | WPS
Regulatory Environment
Approved annual increase (decrease) in rates for customers		4
Customer recoveries (refunds) related to decoupling				8
Michigan Public Service Commission (MPSC) | Retail natural gas rates | 2014 Rates | MGU
Regulatory Environment
Approved annual increase (decrease) in rates for customers					4.5
Approved return on common equity percent reflected in rates of customers					10.25%
Approved percent of capital structure composed of common equity					48.62%
Illinois Commerce Commission (ICC) | Retail natural gas rates | 2015 Rates | PGL
Regulatory Environment
Approved annual increase (decrease) in rates for customers							74.8
Approved return on common equity percent reflected in rates of customers							9.05%
Approved percent of capital structure composed of common equity							50.33%
Amended approved annual increase (decrease) in rates for customers						71.1
Illinois Commerce Commission (ICC) | Retail natural gas rates | 2015 Rates | NSG
Regulatory Environment
Approved annual increase (decrease) in rates for customers							3.7
Approved return on common equity percent reflected in rates of customers							9.05%
Approved percent of capital structure composed of common equity							50.48%
Amended approved annual increase (decrease) in rates for customers						3.5
Illinois Commerce Commission (ICC) | Retail natural gas rates | 2013 Rates | PGL
Regulatory Environment
Adjustment to annual increase (decrease) in rates for customers		2.6
Illinois Commerce Commission (ICC) | Retail natural gas rates | 2013 Rates | NSG
Regulatory Environment
Adjustment to annual increase (decrease) in rates for customers		0.1
Minnesota Public Utilities Commission (MPUC) | Retail natural gas rates | 2014 Rates | MERC
Regulatory Environment
Approved annual increase (decrease) in rates for customers								7.6
Approved return on common equity percent reflected in rates of customers								9.35%
Approved percent of capital structure composed of common equity								50.31%
Annual percent cap on decoupling based on distribution revenues approved in the rate case								10.00%
Interim rates to be refunded to customers			4.7
Subsequent event | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | WPS
Regulatory Environment
Requested return on common equity percent									10.20%
Requested percent of capital structure composed of common equity									50.52%
Subsequent event | Public Service Commission of Wisconsin (PSCW) | Retail electric rates | 2016 Rates | WPS
Regulatory Environment
Requested annual increase (decrease) in rates for customers									94.1
Subsequent event | Public Service Commission of Wisconsin (PSCW) | Retail natural gas rates | 2016 Rates | WPS
Regulatory Environment
Requested annual increase (decrease) in rates for customers									9.4
Subsequent event | Michigan Public Service Commission (MPSC) | Retail electric rates | 2015 Rates | WPS
Regulatory Environment
Approved annual increase (decrease) in rates for customers									4
Approved return on common equity percent reflected in rates of customers									10.20%
Approved percent of capital structure composed of common equity									50.48%
Period of rate recognition									3 years

SEGMENTS_OF_BUSINESS_Details

SEGMENTS OF BUSINESS (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Segment reporting information
Revenues	$1,163.20	$1,638
Depreciation and amortization expense	74.7	70.6
Earnings from equity method investments	17.5	22.9
Miscellaneous income	6.6	5.8
Interest expense	38.2	38.9
Provision (benefit) for income taxes	78.9	81.9
Net income (loss) from continuing operations	131.2	140.2
Discontinued operations	-0.9	12.9
Preferred stock dividends of subsidiary	-0.8	-0.8
Noncontrolling interest in subsidiaries	0	0.1
Net income attributed to common shareholders	129.5	152.4
Intersegment revenues
Segment reporting information
Revenues	0	0
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	-2	-3.3
Interest expense	-2	-3.3
Provision (benefit) for income taxes	0	0
Net income (loss) from continuing operations	0	0
Discontinued operations	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	-2.8	-4.8
Regulated operations
Segment reporting information
Revenues	1,135.30	1,616.80
Depreciation and amortization expense	65.6	62
Earnings from equity method investments	17	22.5
Miscellaneous income	3.5	3.8
Interest expense	25.2	25.1
Provision (benefit) for income taxes	89	93.6
Net income (loss) from continuing operations	136.7	144.7
Discontinued operations	0	0
Preferred stock dividends of subsidiary	-0.8	-0.8
Noncontrolling interest in subsidiaries		0
Net income attributed to common shareholders	135.9	143.9
Regulated operations | Intersegment revenues
Segment reporting information
Revenues	2.6	4.4
Regulated operations | Natural Gas Utility
Segment reporting information
Revenues	839.5	1,267.60
Depreciation and amortization expense	40.6	36.4
Earnings from equity method investments	0	0
Miscellaneous income	0.7	0.3
Interest expense	14.3	13.4
Provision (benefit) for income taxes	65.9	66.7
Net income (loss) from continuing operations	97.8	99.2
Discontinued operations	0	0
Preferred stock dividends of subsidiary	-0.1	-0.1
Noncontrolling interest in subsidiaries		0
Net income attributed to common shareholders	97.7	99.1
Regulated operations | Natural Gas Utility | Intersegment revenues
Segment reporting information
Revenues	2.6	4.4
Regulated operations | Electric Utility
Segment reporting information
Revenues	295.8	349.2
Depreciation and amortization expense	25	25.6
Earnings from equity method investments	0	0
Miscellaneous income	2.8	3.5
Interest expense	10.9	11.7
Provision (benefit) for income taxes	16.4	18.1
Net income (loss) from continuing operations	28.6	31.8
Discontinued operations	0	0
Preferred stock dividends of subsidiary	-0.7	-0.7
Noncontrolling interest in subsidiaries		0
Net income attributed to common shareholders	27.9	31.1
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	17	22.5
Miscellaneous income	0	0
Interest expense	0	0
Provision (benefit) for income taxes	6.7	8.8
Net income (loss) from continuing operations	10.3	13.7
Discontinued operations	0	0
Preferred stock dividends of subsidiary	0	0
Noncontrolling interest in subsidiaries		0
Net income attributed to common shareholders	10.3	13.7
Regulated operations | Electric Transmission Investment | Intersegment revenues
Segment reporting information
Revenues	0	0
Nonutility and nonregulated operations | IES
Segment reporting information
Revenues	0	0
Depreciation and amortization expense	0	0
Earnings from equity method investments	0	0
Miscellaneous income	0	0
Interest expense	0	0
Provision (benefit) for income taxes	0	0
Net income (loss) from continuing operations	0	0
Discontinued operations	-0.8	13
Preferred stock dividends of subsidiary	0	0
Noncontrolling interest in subsidiaries		0
Net income attributed to common shareholders	-0.8	13
Nonutility and nonregulated operations | IES | Intersegment revenues
Segment reporting information
Revenues	0	0
Nonutility and nonregulated operations | Holding Company and Other
Segment reporting information
Revenues	27.9	21.2
Depreciation and amortization expense	9.2	8.7
Earnings from equity method investments	0.5	0.4
Miscellaneous income	5.1	5.3
Interest expense	15	17.1
Provision (benefit) for income taxes	-10.1	-11.7
Net income (loss) from continuing operations	-5.5	-4.5
Discontinued operations	-0.1	-0.1
Preferred stock dividends of subsidiary	0	0
Noncontrolling interest in subsidiaries		0.1
Net income attributed to common shareholders	-5.6	-4.5
Nonutility and nonregulated operations | Holding Company and Other | Intersegment revenues
Segment reporting information
Revenues	0.2	0.4
ATC
Segment reporting information
Equity method investment, ownership interest (as a percent)	34.00%
Earnings from equity method investments	$17	$22.50
Continuing operations
Segment reporting information
Number of reportable segments	4
Discontinued operations
Segment reporting information
Number of reportable segments	1

NEW_ACCOUNTING_PRONOUNCEMENTS_

NEW ACCOUNTING PRONOUNCEMENTS (Details)	3 Months Ended
	Mar. 31, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Potential effective date deferral	1 year